Note: Descriptions are shown in the official language in which they were submitted.
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METHOD AND SYSTEM FOR RECOVERY OF HYDROCARBONS FROM A
SUBTERRANEAN FORMATION
This patent document claims priority from Canadian Patent Application No.
2,991,871 Filed January 15, 2018 entitled: METHOD AND SYSTEM FOR
ENHANCED OIL RECOVERY USING MOVEABLE COMPLETIONS and Canadian
Patent Application No. 2,991,889 Filed January 15, 2018 entitled: A FURTHER
METHOD AND SYSTEM FOR ENHANCED OIL RECOVERY USING MOVEABLE
COMPLETIONS, the entire contents of both of which documents are hereby
incorporated by reference in their entirety.
TECHNICAL FIELD
[0001] This invention relates to recovery of hydrocarbons from a
subterranean
formation. The subterranean formation can including, for example, natural gas,
light
oil, medium oil, heavy oil, oil sands, bitumen, oil shale, shale oil and coal,
mobilised
via the injection of mobilising fluids. In particular, the invention relates
to methods
and systems for mobilising and recovering carbonaceous materials using
completions which are moveable within the subterranean formation so as to be
able
to inject and produce hydrocarbon fluids to/from different regions of the
reservoir at
different times.
BACKGROUND OF THE INVENTION
[0002] Enhanced oil recovery (EOR) generally refers to methods involving
the
injection of mobilising fluids into a reservoir to enhance the production of
hydrocarbons from the reservoir. Hydrocarbons may be present in the reservoir
in
the form of fluids such as oil and gas or solids such as coal and kerogen.
[0003] For light and medium oils, EOR methods generally refer to secondary
or
tertiary methods of recovery, which are commenced after a period of primary
production. For heavy oils, oil sands and bitumen, EOR methods generally refer
to
thermal methods of recovery which are commenced as a primary or sometimes
secondary means of producing hydrocarbons from the reservoir.
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[0004] Enhanced oil recovery can refer to many types of recovery processes,
including immiscible, miscible and thermal methods.
[0005] A common method for EOR involves using patterns of vertical wells
and
injecting a mobilising fluid into a portion of the wells (injectors) and
recovering
petroleum from the remaining wells (producers). Various patterns of the
vertical
injector and producer wells, including 5-spot, 7-spot and 9-spot, and their
inverted
equivalents, have been attempted.
[0006] Another common method for EOR involves using patterns of horizontal
wells and a mobilising fluid into a portion of the wells (injectors) and
recovering
petroleum from the remaining wells (producers). Various patterns of horizontal
injector and producer wells have been attempted
[0007] Various configurations which involve combinations of vertical and
horizontal wells have also been disclosed.
[0008] The use of patterns of vertical wells is common for immiscible and
miscible displacement of the hydrocarbons in the reservoir.
[0009] A common method of immiscible recovery is the water flood. Water
floods
are generally implemented using patterns of vertical wells and injecting water
into a
portion of the wells (injectors) and recovering petroleum from the remaining
wells
(producers). Water floods works best when the reservoir is relatively thick
and the
reservoir is on a dip, so that gravity can be used as a drive mechanism to
enhance
the mobilisation of the petroleum to the producer wells.
[0010] Various additives may be mixed with the water during water flood
operations to improve its properties; for example, by adding polymers to
increase the
viscosity of the water so that the mobility ratio between the petroleum and
water/polymer mixture is more favourable.
[0011] Other fluids which are used for immiscible displacement or pressure
maintenance include nitrogen, methane and light hydrocarbon gases.
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[0012] A common method for miscible recovery is the CO2 flood. When the
pressure is sufficient and the oil properties suitable, then the injected CO2
and the oil
in the reservoir become miscible, allowing more oil to be contacted. Like
water
floods, CO2 floods are often implemented using patterns of vertical wells,
with some
of the wells used as injectors and the remaining wells used as producers
[0013] Other fluids such as light hydrocarbons may also be used for
miscible
recovery depending upon the oil quality and the temperature and pressure of
the
target reservoir.
[0014] Thermal processes are generally utilised for the purpose of
recovering
viscous petroleum from heavy oil, oil sands, and bitumen reservoirs. The
viscosities
of these petroleum resources are too high to be produced without heating.
Generally
heating may be undertaken by injecting hot water, steam, by performing in situ
combustion by injecting an oxidant or by downhole heating using electrical
heaters
and other methods. Hot water injection has low efficacy and is generally not
preferred. Control of the combustion front formed during in situ combustion
has
historically been difficult and therefore in situ combustion is currently only
applied in
a limited number of reservoirs to produce commercial quantities of
hydrocarbons.
Electrical heating is relatively expensive and is also slow to mobilise
reservoir fluids
as it relies primarily on heat conduction. Thus, steam injection is generally
the
preferred thermal method of recovering viscous petroleum resources.
[0015] The most common methods of steam injection include the steam flood
and steam assisted gravity drainage (SAGD).
[0016] Steam floods generally involve drilling a pattern of vertical wells
and
injecting steam into a portion of the wells (injectors) and recovering
petroleum from
the remaining wells (producers). Various patterns of the injector and producer
wells,
including 5-spot, 7-spot and 9-spot, and their inverted equivalents have been
attempted. Steam flooding works best when the reservoir is relatively thick
and the
reservoir is on a dip, so that gravity can aid the drive mechanism to enhance
the
mobilisation of the petroleum to the producer wells.
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[0017] The SAGD process involves positioning an injection well above a
production well and injecting steam into the upper well to form a steam
chamber
which heats and mobilises the oil which flow to the production well below.
SAGD is the preferred method for recovering oil sands and some heavy oil
reservoirs. SAGD works best in relatively thick (>15 m thick) and homogeneous
reservoirs at depths less than about 800 m. SAGD is not effective in thin
reservoirs
due to the requirement to place the steam injector well above the petroleum
producer well. SAGD is also not effective when the reservoir is fractured or
highly
heterogeneous, which will accelerate bypassing of the injected steam to the
producer, reducing petroleum recovery and increasing the steam oil ratio (SOR)
to
uneconomic values. SAGD is also not practiced in deep reservoirs, due to i)
heat
losses during steam injection and ii) the higher steam temperatures required
at
higher pressures. SAGD has been applied with considerable success in
recovering
Athabasca bitumen in Canada.
[0018] SAGD has had limited operational success to date in heterogeneous
reservoirs, such as the carbonate reservoirs in Canada.
[0019] A common issue with existing EOR methods is to ensure that the
mobilising fluids contact the maximum amount of the reservoir and that
breakthrough
of the mobilising fluids to the producer wells is delayed for as long as
possible. For
once the mobilising fluids reach the producer wells, the recovery rate of
hydrocarbons from the reservoir diminishes rapidly.
[0020] Solutions which are commonly applied to delay the breakthrough of
the
mobilising fluids are: i) inject alternating fluids and/or additives to
improve the
mobility ratio between the injected fluid and the reservoir hydrocarbons, ii)
install
injection and inflow control devices to manage the pressure distribution along
the
injector and/or producer wells and iii) change the configuration and spacing
of the
injector and producer wells.
[0021] In many cases hydrocarbon reservoirs with heterogeneous properties
are
avoided altogether since the existing methods are ineffective and uneconomic.
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[0022] In many cases, primary production is undertaken using a single well
drilled into the formation. The well may be vertical or it may be horizontal.
Common
examples include wells designed for cold production in heavy oil deposits and
in
offshore reservoirs.
[0023] The common methods of EOR, mentioned above, which may involve
adding injectors to inject mobilising fluids into the reservoir, may not be
practical or
may be too expensive to be economic.
[0024] An invention which would enable the use of a single well bore with
EOR
methods and be suitable for use in thin, homogeneous, heterogeneous and/or
fractured reservoirs would be an important improvement over the prior art. An
invention which would enable the recovery of more hydrocarbons from an
existing
well bore, would be especially attractive.
[0025] Methods using a single wellbore to recover hydrocarbons from a
reservoir
include cyclic "huff and puff" approaches which can be used with immiscible,
miscible and thermal recovery methods. Typically, the procedure is to inject a
mobilising fluid into the formation from a wellbore, to allow the mobilising
fluid to
soak into the reservoir and then after a period of time soaking, produce a
mixture of
mobilising fluid and hydrocarbon fluids to surface. The approach has been used
most frequently for the miscible recovery using CO2 and for thermal recovery
using
steam (generally known as cyclic steam stimulation, CSS).
[0026] Cyclic methods by their nature exacerbate heterogeneity in the near
well
bore region of the reservoir. The initial slugs of mobilising fluids find
their way
preferentially into the high permeability areas of the reservoir and drain the
hydrocarbons, introducing further heterogeneity in the form of fluid
saturation and
permeability changes.
[0027] When considering miscible processes, pattern floods using CO2 and
Water Alternating Gas (WAG) are generally preferred to single well bore cyclic
processes using vertical or horizontal wells. The main reason is that cyclic
injection
of miscible fluids has a low recovery factor.
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[0028] Thermal recovery of viscous petroleum deposits can be undertaken
with
CSS using vertical and horizontal wells. CSS works in relatively thin
formations.
However, a major disadvantage of CSS is that it only recovers between 5 and
15%
of the Original Oil In Place (00IP). Thus, a large quantity of hydrocarbons
are left
behind in the reservoir. In addition, CSS is less effective in heterogeneous
formations, as the injected steam will preferentially flow into the fractures,
thereby
bypassing a large portion of the reservoir and leading to even lower recovery
factors.
[0029] A variety of methods have been described using a single well-bore to
recover petroleum from subterranean reservoirs.
[0030] US Patent 5,771,973 to Jensen et al. describes a method of injecting
a
mobilising fluid through a tubing string at a raised end of a horizontal
wellbore, and
producing a mixture of mobilising fluid and hydrocarbons from the heel of the
well
bore through a second tubing string.
[0031] US Patent 5,131,471 to Duerksen et al. describes a method of
injecting a
mobilising fluid through a vertical wellbore via a tubing string and
perforation into the
formation and recovering mobilised fluids via a second tubing string located
below a
packer.
[0032] US Patent 5,215,149 to Lu describes a method of constructing a
horizontal well, perforating the well at the toe and at the heel and
installing a tubing
string and packer on the heel side of the perforations near the toe of well.
Steam is
injected into the annulus and enters the formation via the perforations at the
heel of
the well. Mobilised hydrocarbons are then recovered via the perforations at
the toe of
the well and produced to surface via the tubing string.
[0033] US Patent 4,116275 to Moore et al. describes a method of producing
viscous formations by circulating steam within a wellbore and then injecting
steam in
a cyclic manner into the formation to mobilise and produce hydrocarbons.
[0034] US Patent 5,626,193 to Nzekwu et al. describes a method of producing
viscous formations from a single horizontal wellbore via a steam flooding
gravity
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drainage process. The process works by injecting steam and hot water
condensate
into the formation at the toe of the wellbore and establishing a steam
chamber. The
steam chamber is them propagated towards the heel of the wellbore by pressure
gradients. Steam is injected into the toe of the well via a tubing string and
retrieved
at the heel via a thermal packer and pump arrangement.
[0035] US Patent 5,148,869 to Sanchez discloses a single well bore process
for
the in-situ extraction of viscous oil by gravity action using steam plus a
solvent. A
horizontal well is drilled into the formation and a steam/solvent mixture is
injected
into the reservoir from the top of the wellbore via a conduit from surface.
Oil is
recovered from the bottom of the wellbore into a second conduit and
transported to
surface. The process operates via heat conduction, heat convection and gravity
drainage.
[0036] US Patent 5,167,280 to Sanchez et al. discloses a single well bore
process for stimulating a reservoir using a solvent. Solvent permeates from
the
wellbore into the reservoir, reducing the viscosity of the oil in the vicinity
of the well
bore.
[0037] US Patent 9,328,595 B2 to Kjoorholt discloses a single well bore
process
for steam assisted gravity drainage. In this process, two conduits each with a
plurality of permeable sections are placed within the well bore, one conduit
for steam
injection and one conduit for production of reservoir fluids. The invention
discloses
that the injection sections are staggered longitudinally with respect to the
production
sections within the single well bore. This configuration promotes the
formation of
steam chambers which mobilise the hydrocarbons in the reservoir between the
various injection and production sections.
[0038] An invention which would enable the use of a pattern of well bores
with
EOR methods and be suitable for use in thin, homogeneous, heterogeneous and/or
fractured reservoirs would be an important improvement over the prior art. An
invention which would enable the recovery of more hydrocarbons from an
existing
pattern of well bores, would be especially attractive.
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[0039] A variety of methods have been described using a pattern of well-
bores to
recover petroleum from subterranean reservoirs.
[0040] US Patent 4,850,429 to Mins et al. discloses use of a triangular
pattern of
horizontal well-bores wherein a recovery fluid is injected such as steam is
injected in
some of the wells in the pattern and hydrocarbons ae recovered from the
remaining
wells in the pattern.
[0041] US Patent 4,598,770 to Shu et al. discloses the use of a pattern of
horizontal and vertical wells with steam injection for the recovery of heavy
oil.
[0042] US Patent 5,201,815 to Hong et al. discloses an inverted nine-spot
well
pattern for use with steam enhanced oil recovery wherein the well completion
in the
sidewells is restricted to the lower 20% of the reservoir.
[0043] US Patent 5,915,477 to Stuebinger et al. discloses use of a pattern
of
injection and production well-bores for enhanced oil recovery wherein there is
at
least two production strata.
[0044] All of the aforementioned prior art use static completions; i.e.
completions
which are fixed in time and space. None of the prior art mention the
advantages of
using movable completions to be able to inject and produce hydrocarbon fluids
to/from different regions of the reservoir at different times.
[0045] Any discussion of prior art information in this specification is not
to be
taken as any form of acknowledgement that that prior art information would be
considered common general knowledge by a person of skill in the art, either in
Australia or in any foreign country.
SUMMARY
According to a first aspect there is provided a method to recover hydrocarbons
from
a reservoir of a subterranean formation comprising a single horizontal well
bore, the
method comprising the steps of:
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a) injecting a mobilising fluid into the reservoir at a first location to
create a first
mobilised zone, the first mobilised zone including a mixture of mobilised
fluids
including injected mobilising fluid and mobilised hydrocarbons;
b) withdrawing the mixture of mobilised fluids that flow out of the reservoir
of the
hydrocarbon bearing subterranean formation as a produced fluid; and
c) changing the location of injection of mobilising fluid and repeating steps
a) and b)
one or more times so as to inject mobilising fluid into the reservoir at one
or more
subsequent further location(s) remote from the first location to create one or
more
subsequent further mobilised zone(s) remote from the first mobilised zone;
wherein the mobilising fluid is injected via a completion assembly
arranged in the horizontal well bore, and the produced fluid is removed via
the same
completion assembly arranged in the horizontal well bore.
[0046] The mobilising fluid is injected via a completion assembly and the
produced fluid is removed via the same completion assembly arranged in the
horizontal reservoir. This means that the method can be applied to a single
well. By
"single well" it is meant that the well is disposed at a distance from any
other well
such that injected mobilising fluid and produced fluid enters the same
completion
assembly, and the fluids do not interact with any other well in terms of the
produced
fluid entering that other well. A single well arrangement may have the
following
advantages:
i. the mobilising fluid injection location(s) can be precisely controlled
ii. the flux of the mobilising fluid can be precisely controlled
iii. The completion assembly may be installed in existing or "old" wells to
enable additional hydrocarbons to be recovered from the formation
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[0047] The above advantages can in some embodiments lead to increased
hydrocarbon recovery and enable maximum utilization of the mobilising fluids
to be
achieved. In other cases, the advantage of embodiments of the present
invention is
the ability to recover hydrocarbons from a reservoir using a single well bore,
which in
the prior art would have required at least two individual well bores to
achieve the
same recovery.
[0048] The method can comprise the continuous injection of mobilising fluid
as
the produced fluid is withdrawn.
[0049] Following the step of changing the location of injection of
mobilising fluid,
the subsequent further location of injection can overlap with the immediately
preceding location of injection.
[0050] The completion assembly can comprise a completion tubing and a
horizontal well liner comprising a plurality of perforations spaced along
substantially
a length of the well liner. The completion tubing can be installed within the
well liner.
The tubing can be adapted to inject the mobilising fluid into the reservoir.
The tubing
can be adapted to move in the reservoir.
[0051] The completion assembly can comprise a completion tubing, a
horizontal
well liner and one or more completion devices, whereby each completion device
has
apertures that can be opened and closed, thereby enabling the injected fluids
to be
injected at one location along the horizontal well bore at one time, and at
another
location at another time. Similarly, the produced fluids can be produced from
one
location at one time and another location at another time.
[0052] Alternatively, the completion assembly, can be as described in
relation to
the system described herein.
[0053] In embodiments, the present invention relates to methods of
recovering
hydrocarbon containing fluids by utilising a completion assembly that
specifically
enables the injection of mobilising fluids and the production of reservoir
fluids to/from
different regions of the reservoir at different times
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[0054] In order to prevent, or at least reduce, the propensity for the
mobilising
fluids to bypass the reservoir and return to surface, one or more sealing
devices can
be installed to form a seal between the completion assembly and the well
liner. The
one or more seals can assist in preventing or at least substantially reducing
a direct
connection from forming between the location of injection, and the location
through
which the production fluid enters the completion assembly. Part of the
function of
sealing devices is to separate the injection and production locations in
space; with
this in mind, sealing them from each other but having them close together is
in some
embodiments ineffective. A distance between the location of injection and
location of
production fluid intake can be calculated to be one where there is no (or at
least a
reduced) tendency for a substantial amount (80, 90 or 95 or 100 /0) of the
injected
mobilised fluid to simply return to the completion assembly as a part of the
production fluid.
[0055] Depending on the nature of the reservoir and the mobilising fluids,
it may
be desirable to avoid certain regions of the reservoir altogether. For
example,
regions with very low permeability, very high levels of fractures or regions
which are
highly heterogeneous.
[0056] In other cases, it may be desirable to "quickly" sweep the injection
of
mobilising fluids through particular regions of the reservoir, by moving parts
of the
completion assembly. For example, when fractures are present in the reservoir,
excessive bypassing of the mobilising fluids from the injection side to the
production
side may occur, reducing the ratio of hydrocarbons to mobilising fluids in the
produced fluids; thereby increasing the costs of production. The reservoir
fluids can
be referred to as produced fluid.
[0057] In other cases, it may be desirable to inject the mobilising fluids
in one
region at one time, and then another region at another time and alternate the
injection between these regions over time in a cyclic manner.
[0058] According to a second aspect there is provided a system for
recovering
hydrocarbons from a reservoir of a subterranean formation comprising a single
horizontal well bore, the system comprising:
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a completion assembly disposed in the single horizontal well bore and adapted
to
both:
i. inject from an injection point at a first injection location a
mobilising fluid into
the reservoir to create a first mobilised zone, the first mobilised zone
including a
mixture of mobilised fluids including injected mobilising fluid and mobilised
hydrocarbons; and
ii. withdraw from a withdrawal point at a first withdrawal location the
mixture of
mobilised fluids that flow out of the reservoir of the hydrocarbon bearing
subterranean formation as a produced fluid;
wherein the completion assembly comprises a plurality of injection points to
permit changing of the location of injection of mobilising fluid to one or
more
subsequent further location(s) remote from the first injection location to
create one or
more subsequent further mobilised zone(s) remote from the first mobilised
zone; and
wherein the completion assembly comprises a plurality of withdrawal points to
permit changing of the location of withdrawal of produced fluid to one or more
subsequent further location(s) remote from the first withdrawal location.
[0059] Unless the context makes clear otherwise, the description and
elaboration
of the method above also applies to the description of the system. For
example, the
completion assembly can comprise a completion tubing, a horizontal well liner
and
one or more completion devices, whereby each completion device has apertures
that
can be opened and closed, thereby enabling the injected fluids to be injected
at one
location along the horizontal well bore at one time, and at another location
at another
time. Similarly, the produced fluids can be produced from one location at one
time
and another location at another time.
[0060] The completion assembly can comprise two conduits, an inner conduit
and an outer conduit, each of the two conduits can be in fluid communication
with
the reservoir, and the two conduits are arranged one inside the other
concentrically.
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[0061] Alternatively, the two conduits are arranged one inside the other
eccentrically so that at least a part of the wall of the inner conduit abuts
the wall of
the outer conduit.
[0062] The completion assembly can comprise a plurality of completion
devices,
each completion device comprising a plurality of apertures that can be opened
to
provide the fluid communication between one or both of the conduits and the
reservoir; and the apertures can be closed so as to close off the fluid
communication
between one or both of the conduits and the reservoir.
[0063] Each completion device (or at least some of the completion devices
provided) can provided with a sliding sleeve slidable to open or close
apertures in
the inner and or outer conduits.
[0064] In different positions the sliding sleeve can provide:
a. the apertures of the inner conduit are closed and the apertures of the
outer
conduit are closed; or
b. the apertures of the inner conduit are open and the apertures of the
outer
conduit are open; or
c. the apertures of the inner conduit are open and the apertures of the
outer
conduit are closed; or
d. the apertures of the inner conduit are closed and the apertures of the
outer
conduit are open.
[0065] In an embodiment, the injection of a mobilising fluid from an
injection point
into the reservoir comprises injection via open apertures of a first
completion device;
and changing the location of injection of mobilising fluid comprises injecting
via open
apertures of a second completion device, wherein the sliding sleeve of the
second
completion device is moved to open the apertures for injection. In some
embodiments, the sliding sleeve of the first completion device can be is moved
to
close the apertures for injection.
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[0066] In an embodiment, the the withdrawal of produced fluid comprises
withdrawal via open apertures of a first completion device; and the system
further
includes changing the location of withdrawal of produced fluid, wherein
changing the
location of withdrawal of produced fluid comprises withdrawal via open
apertures of a
second completion device, wherein the sliding sleeve of the second completion
device is moved to open the apertures for withdrawal. In some embodiments, the
sliding sleeve of the first completion device can be moved to close the
apertures for
withdrawal.
[0067] In an embodiment, a first completion device injects mobilising fluid
into the
reservoir at a first injection location; a second completion device withdraws
produced fluid at a first withdrawal location; the first completion device
ceases
injecting mobilised fluid, and is changed to withdraw produced fluid at a
second
withdrawal location; the second completion devices ceases withdrawing produced
fluid, and is changed to inject mobilising fluid at a second injection
location.
[0068] An advantage of using a moveable completion assembly to inject
mobilising fluids into the reservoir from the well is that greater precision
can be
possible in the injection of the mobilising fluid. In particular, by using the
completion
assembly in the methods and systems as described herein, the injection of the
mobilising fluid(s) can be focused over only a portion of the well bore and
hence the
flux of mobilising fluids into the reservoir may be controlled to ensure
optimum use of
the mobilising fluids. Typically, in enhanced oil recovery operations,
achieving a high
ratio of hydrocarbons to the mobilising fluids is desirable. In many enhanced
oil
recovery methods controlling the flux of the injected mobilising fluids is
critical to
achieving the conditions required to mobilise the maximum amount of
hydrocarbons
from the reservoir.
[0069] It will be appreciated by those skilled in the art, that by moving
the location
of the injection zone along the horizontal well bore, operators can attempt to
achieve:
i) an efficient use of the mobilising fluids, ii) sustained production of
hydrocarbon
fluids and iii) high hydrocarbon recovery factor. Each of these parameters
directly
relates to the economic performance of an enhanced oil recovery operation.
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[0070] The mobilising fluids can be injected into the hydrocarbon bearing
reservoir through at least one opening in the tubing of the completion
assembly. If
the tubing is arranged in a well liner, the mobilising fluid can then pass
through an
open area such as perforations in the liner. In the reservoir, a zone of
mobilised
hydrocarbons is therefore created, which will comprise naturally occurring
hydrocarbons and the mobilising fluids; and or the products of any physical
and
chemical interactions which occur between them. The zone of mobilised
hydrocarbons is a zone located in the vicinity of the completion assembly from
which
mobilising fluids and produced fluids are injected to and extracted from the
reservoir,
respectively.
[0071] The resulting mixture of fluids from the mobilised zone can be
referred to
as the produced fluids. The produced fluids from the zone of mobilised
hydrocarbons
may flow via gravity, pressure and or other means back through the liner and
may
enter the completion tubing. From there the produced fluids may travel to the
heel of
the well and be produced to surface via a pump and production tubing. The
completion tubing can be a concentric tubing comprising an inner tube and an
outer
tube. The tubing can comprise at least one opening in the form of a first
series of
apertures. The first series or set of apertures can be in fluid communication
with the
inner tube. The tubing can comprise a further series of apertures spaced along
the
length of the tubing. The further series of apertures can be in fluid
communication
with the outer tube. The first series of apertures can be towards the tip of
the tubing.
The further series of apertures can be remote from the tip.
[0072] In an embodiment, the apertures are arranged on a completion device.
There can be more than one completion device installed onto the completion
tubing.
The advantage of the completion device is that is can integrate all of the
required
functions in one device and may be readily installed onto and uninstalled from
the
completion tubing from the rig equipment at surface. By having a standard
completion device, multiple may be easily installed onto the completion tubing
as it is
positioned into the wellbore. The completion device may also incorporate
common
features of existing oil and gas completions such as monitoring
instrumentation,
expansion devices to manage thermal or pressure driven expansion,
inflow/outflow
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devices to control the rate of injection/production of fluids to/from the
reservoir, and
sealing devices and safety devices such as quick-disconnect mechanisms.
[0073] The apertures can be any desired pattern of open area; for example
slots,
holes or even just an open end of the tubing. The first series of apertures
can
comprise a cluster of 2, 3, 4, 5, 6, 7, 8, 9, or 10 apertures each of about 5,
10, 15,
20, 25 mm in diameter. There can be more than one set of first series of first
apertures in the completion tubing, each set spaced apart from one another.
The first
series of apertures can comprise a cluster of 2, 3, 4, 5, 6, 7, 8, 9, or 10
apertures
each of about 5, 10, 15, 20, 25 mm in diameter. There can be more than one set
of
further series of apertures in the completion tubing, each set spaced apart
from
another.
[0074] In an embodiment, the distance between the first series of apertures
and
the second series of apertures is of the order of the thickness of the
formation +/- 5
or 10 %. For example, if the well is arranged within a formation which is 25 m
thick,
the spacing can be about 25 m.
[0075] In an embodiment, the distance between the first series of apertures
and
the second series of apertures is chosen to maximise hydrocarbon recovery by
minimising the opportunity for the mobilizing fluids to by-pass the reservoir.
[0076] The apertures in the completion tubing can deliver the mobilising
fluid into
the horizontal well and then into the reservoir. If the tubing is a concentric
tubing,
there can be more than one mobilising fluid. The first series of apertures can
deliver
a first mobilising fluid, and the further series of apertures can deliver a
second
mobilising fluid.
[0077] Alternatively, the further series of apertures delivers a mobilising
fluid and
the first series of apertures receives withdrawn produced fluid. The mixture
of
mobilised produced fluid can flow under gravity and/or pressure through the
perforations in the well liner and through the first series of apertures into
the tubing.
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[0078] Further alternatively, the first series of apertures delivers a
mobilising fluid
and the further series of apertures receives withdrawn produced fluid. The
mixture of
produced mobilised fluid can flow under gravity and/or pressure through the
perforations in the well liner and through the further series of apertures
into the
tubing.
[0079] When the hydrocarbons in the zone of mobilised hydrocarbons have
been
produced using the completion assembly, the location of the completion tubing
may
be moved longitudinally along the horizontal well bore, to enable the
mobilisation of
hydrocarbons from a new portion of the reservoir.
[0080] The step of changing the location of the injection of mobilising
fluid in the
well can comprise moving the tubing. The step of moving of the tubing can
comprise
retracting the tubing. The step of moving of the tubing can comprise advancing
the
tubing. The step of retracting the tubing can be undertaken by removal of
tubing
sections. The step of retracting the tubing can be by winding up the tubing.
The step
of advancing the tubing can be undertaken by addition of tubing sections. The
step
of advancing the tubing can be by winding out the tubing from a coil.
[0081] When the hydrocarbons in the zone of mobilised hydrocarbons have
been
produced using the completion assembly, the location of the injection point in
the
completion tubing may be moved longitudinally along the horizontal well bore,
to
enable the mobilisation of hydrocarbons from a new portion of the reservoir.
[0082] The step of changing the location of the injection of mobilising
fluid in the
well can comprise changing the injection point from the tubing. Old or
previous
injection points can be closed. New or subsequent injection points can be
opened.
[0083] In an embodiment, the new location of the completion assembly, may
overlap with its old position, thereby creating an overlap between the old and
new
location of the zone of mobilised hydrocarbons.
[0084] Generally, it is preferable, especially in thermal EOR processes, to
ensure
that the zone of mobilised hydrocarbons formed by operation at successive
positions
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of the completion assembly overlap. This may ensure that there is a zone of
sufficient permeability to inject the mobilising fluids. It may also help to
ensure a high
recovery factor for the hydrocarbons, as all of the reservoir is contacted
successively
with mobilising fluids.
[0085] In an embodiment the completion device can comprise of two conduits,
with pathways for the flow of fluids between each of the conduits and the
outside of
the device. In an embodiment, the conduits can be arranged one inside the
other,
forming an inner conduit (annulus) and an outer conduit (annulus). In an
embodiment
the conduits in the completion device may be arranged concentrically or
eccentrically.
[0086] In an embodiment one conduit may be used for the injected fluid and
one
conduit may be used for the produced fluid. In an embodiment, the two conduits
may
be used for the injected fluid or the two conduits may be used for the
produced fluid.
[0087] In an embodiment the completion device incorporates one or more
sliding
sleeves that may be moved to open and close pathways within the device and the
apertures on the outside of the device for the flow of the injected fluids and
for the
flow of the produced fluids.
[0088] In an embodiment the completion device incorporates a sliding sleeve
that
can be configured with one or more of the following positions:
i) enabling flow from the inner conduit to/from the outside of the device
ii) enabling flow from the outer conduit to/from the outside of the device
iii) disabling flow from the inner and outer conduit to/from the outside of
the
device
iv) enabling flow from the inner conduit to/from the outer conduit inside
the
device
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[0089] In an embodiment, the sliding sleeve(s) may be operated using any
conventional means, including coiled tubing or wireline tools to latch on to
the sleeve
and move its position, the use of drop balls, the use of hydraulic actuators
and any
other method known in the art.
[0090] In an embodiment the completion assembly can comprise of a number of
completion devices connected directly together. In an embodiment the
completion
devices can be connected together using standard tubings.
[0091] In an embodiment, the completion devices may be installed in a well
bore
with a well liner. In an embodiment, the completion devices may be installed
in a well
bore without a well liner.
[0092] In an embodiment, the step of changing the location of the injection
of
mobilising fluid in the well can comprise of moving a sliding sleeve in a
completion
device to open apertures, thereby enabling mobilizing fluid to enter the
reservoir at a
new location along the well bore.
[0093] In an embodiment, the step of changing the location of the injection
of
mobilising fluid in the well can comprise of moving a sliding sleeve in a
completion
device to close apertures, thereby disabling mobilizing fluid to enter the
reservoir at
an old location along the well bore.
[0094] In an embodiment, the step of changing the location of the
production
fluids in the well can comprise of moving a sliding sleeve in a completion
device to
open apertures, thereby enabling produced fluids to enter a conduit in the
completion
device from the reservoir at a new location along the well bore.
[0095] In an embodiment, the step of changing the location of the produced
fluids
in the well can comprise of moving a sliding sleeve in a completion device to
close
apertures, thereby disabling produced fluids to enter a conduit in the
completion
device from the reservoir at an old location along the well bore.
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[0096] The mobilising fluid can be selected from one or more of steam,
oxidants
(oxygen containing fluids), solvents, carbon dioxide, light hydrocarbons such
as
methane, ethane, propane and butane, water, nitrogen and any other fluids
usually
used for the same purpose. Where there is a first mobilising fluid and a
second
mobilising fluid, the two fluids can be the same or different from one
another.
[0097] An advantage of using a primary and secondary mobilising fluid is
that the
presence of the secondary mobilising fluid can reduce the direct contact of
the
primary mobilising fluid with the produced fluids in the well bore by creating
a fluid
blanket; thereby reducing unwanted interactions such as mixing and reaction.
[0098] Another advantage of using a primary and secondary mobilising fluid
is
that the temperature of the completion assembly, completion device, sealing
device,
liner and well bore can be better controlled. For example, when the primary
mobilising fluid is an oxidant, the injection of water or steam as the
secondary
mobilising fluid can be used to manage the temperatures inside the well bore.
By
ensuring temperatures remain within an acceptable range, the mechanical
integrity
of the liner, completion device and sealing device may be assured and the
sealing
performance of the sealing devices can be maximised. In this example, if too
high
temperatures are measured in the completion device then the ratio of secondary
to
primary mobilising fluids can be increased; while if too low temperatures are
measured in the completion device then the ratio of secondary to primary
mobilising
fluids can be decreased.
[0099] In an embodiment, the method can be employed for the recovery of
hydrocarbons from subterranean formations, including light, medium and heavy
oils,
tight oil, tight gas, oil shale, shale oil, oil sands and bitumen reservoirs
using a
moveable completion in a single well.
[0100] In an embodiment the hydrocarbon bearing subterranean formation
comprises heavy oil, oil sands and/or bitumen and the mobilising fluid is
steam. In
this situation the zone of mobilised hydrocarbons would be generated via the
creation of a steam chamber and the condensing of steam to water to heat up
and
mobilise hydrocarbons in the reservoir. In the case of steam injection, the
mobilised
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hydrocarbon zone would likely be at a temperature in the range of from about
150 to
about 300 C.
[0101] In an embodiment the hydrocarbon bearing subterranean formation
comprises light oil, medium oil, heavy oil, oil sands and/or bitumen and the
mobilising fluid is an oxidant. The oxidant may comprise a mixture of one or
more of
air, oxygen, water, carbon dioxide and steam. In this situation the zone of
mobilised
hydrocarbons would be generated in part via the combustion of a portion of the
hydrocarbons with oxygen. The mobilised hydrocarbon zone would be at various
temperatures up to about 900 C. During in situ combustion a narrow high
temperature combustion zone up to about 900 C is created, along with a
thermal
cracking zone where temperatures in the range of from about 300 to about 600
C
and a steam zone at temperatures below about 300 C.
[0102] In an embodiment the hydrocarbon bearing subterranean formation
comprises coal, oil shales and/or kerogen and the mobilising fluid is an
oxidant. In
this situation the zone of mobilised hydrocarbons would be generated in part
via the
combustion and gasification of a portion of the hydrocarbons with oxygen,
steam and
carbon dioxide. The mobilised hydrocarbon zone would be at various
temperatures
up to about 1500 C and the mobilised hydrocarbons would consist of a
significant
quantity of synthesis gases, such as carbon monoxide and hydrogen, along with
condensable hydrocarbons of varying chain lengths.
[0103] In an embodiment, steam may be generated in the completion assembly
when the mobilising fluid contains a portion of liquid water at surface and
sufficient
heat is transferred from the produced fluids during operation to the
mobilising fluid to
turn the liquid water to steam. This counter-current heat transfer mechanism
between the mobilising and produced fluids is of significant advantage in some
applications.
[0104] For example, when an oxidant and liquid water is injected at
surface, it
may become a mixture of oxidant and steam when it reaches the completion
device
and is injected into the reservoir. Steam is an effective mobilising fluid in
thermal
enhanced oil recovery applications.
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[0105] In addition, the evaporation of water into steam can absorb a large
amount of energy at a constant temperature, due to the latent heat of
evaporation.
The evaporation temperature of water in the reservoir will vary between about
100
and 300 C, depending upon the pressure. Therefore, the co-injection of water
with
other mobilising fluids, such as an oxidant, together with counter-current
heat
transfer of the produced fluids can be used to control the temperature of the
completion assembly inside the well bore during operations.
[0106] In embodiments, when an oxidant is used as a mobilising fluid, any
excessively high temperature of the produced fluids is beneficially used to
evaporate
water co-injected with the mobilising fluid into steam such that the
completion
assembly is controlled to the evaporation temperature of water +/-10% at the
prevailing pressure in the completion assembly, by varying the:
i) ratio of water to oxygen in the mobilising fluid.
ii) rate of injection of the mobilising fluid.
[0107] Thus, in some applications involving combustion, the single well
bore
configuration and completion assembly can have the advantage of being able to
generate steam for injection into the reservoir as a mobilising fluid, while
simultaneously controlling the temperature of the well bore and completion
assembly
to a temperature close to the evaporation temperature of water in the
reservoir at the
operating pressure.
[0108] In an embodiment the hydrocarbon bearing subterranean formation
comprises heavy oil, oil sands and/or bitumen and the mobilising fluid is a
heated
solvent. In this situation the zone of mobilised hydrocarbons would be
generated via
heating and mixing of the hydrocarbons with the injected solvent. Solvents
considered to be suitable for mobilising heavy oil formations include light
hydrocarbons such as ethane, propane and butane.
[0109] In an embodiment the hydrocarbon bearing subterranean formation
comprises heavy oil, oil sands and/or bitumen and the mobilising fluid is a
mixture of
steam and/or oxidant and/or a heated solvent. In this situation the zone of
mobilised
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hydrocarbons would be generated via heating and mixing of the hydrocarbons
with
the injected mobilising fluid.
[0110] In an embodiment the hydrocarbon bearing subterranean formation
consists of light oil, medium oil, heavy oil or bitumen and the mobilising
fluid is a fluid
miscible with the hydrocarbons at the temperature and pressure conditions
present
in the reservoir. Fluids generally considered suitable for miscible injection
into
hydrocarbon formations include carbon dioxide and light hydrocarbons such as
methane, ethane, propane and butane. In this situation the zone of mobilised
hydrocarbons would be generated via miscible mixing of the hydrocarbons with
the
mobilising fluid.
[0111] In an embodiment the hydrocarbon bearing subterranean formation
comprises light oil, medium oil, heavy oil or bitumen and the mobilising fluid
is a fluid
immiscible with the hydrocarbons at the temperature and pressure conditions
present in the reservoir. Fluids generally considered suitable for immiscible
injection
into hydrocarbon formations include water and mixtures of water with various
additives, such as polymers. Gases at low pressure may also be used for
immiscible
injection. In this situation the zone of mobilised hydrocarbons would be
generated via
immiscible displacement of the hydrocarbons with the mobilising fluid.
[0112] In an embodiment the hydrocarbon bearing subterranean formation
comprises light oil, medium oil, heavy oil or bitumen and the mobilising fluid
8 is a
fluid for use in microbial enhanced oil recovery (MEOR). Fluids generally
considered
suitable for MEOR include various combinations of oxygen, water, microbes and
nutrients that enhance microbial activity in the reservoir. In this situation
the zone of
mobilised hydrocarbons would be generated via microbial activity that is
enhanced
by the mobilising fluid.
[0113] In an embodiment the mobilising fluid may be injected continuously.
In an
embodiment the mobilising fluid may be injected discontinuously, for example
as per
cyclic processes (such as "huff and puff") and/or as per sequential processes
(such
as water-alternating-gas (WAG) injection).
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[0114] In an embodiment the produced fluids may be produced continuously.
In
an embodiment the produced fluids may be produced discontinuously, for example
as per cyclic processes (such as "huff and puff") and/or as per sequential
processes
(such as water-alternating-gas (WAG) injection).
[0115] In an embodiment, an upgrading device is provided in the path of the
produced fluid so as to upgrade the produced fluid as it is withdrawn through
the
completion assembly. The upgrading device can be a physical device, a
material, a
mixture of materials and/or a sequence of materials which improves the quality
of the
produced hydrocarbon fluids from the reservoir.
[0116] In an embodiment, the quality of the produced fluids is monitored.
Monitoring of the quality of the produced fluids can provide an indicator of
how to
move the location of the injected mobilising fluids through the reservoir. A
low ratio of
hydrocarbons to mobilising fluids may indicate that the frequency and/or
distance
which the injection zone is moved should be increased. A high ratio of
hydrocarbons
to mobilising fluids may indicate that the frequency and/or distance which
injection
zone is moved should be decreased.
[0117] Therefore, in some embodiments the method can further comprise the
steps of:
i) monitoring the produced fluid from each of the mobilised zones to
determine the ratio of used mobilising fluid and mobilised hydrocarbons in the
produced fluid;
ii) selecting or otherwise adjusting the frequency of the change in the
location of injection of mobilising fluid and or the distance between the
first location
and the one or more further locations depending on the monitored ratio.
[0118] When a low ratio of hydrocarbons to mobilising fluids is reached the
frequency and/or distance which the injection zone is moved should be
increased.
When a high ratio of hydrocarbons to mobilising fluids is reached the
frequency
and/or distance which the injection zone is moved should be decreased. The
ratio
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will depend on the type of mobilising fluid used; each fluid will have
different
properties. Also, the ratio will depend on the properties of the reservoir.
[0119] Mobilising fluids may include fluid and/or solid additives and
catalysts. In
an embodiment, the first and or second mobilising fluid comprises
nanoparticles and
or nanofluids. The nanoparticles can comprise iron, nickel, copper, vanadium,
or
other metals which have been shown to have a catalytic effect on upgrading
crude
oils. For example, Rezai etal., 2013 (Fuel 2013, v113, pp516-521) show that
nanoparticles are effective in reducing the activation energy of combustion
reactions.
[0120] Another advantage of using two mobilising fluids is that one of the
mobilising fluids may be used to inject a catalyst material, in the form of a
fluid and/or
solid, into the reservoir that can catalyse the reaction between the other
mobilising
fluid and the naturally occurring hydrocarbons. For example, catalysts may be
mixed
with the secondary mobilising fluid or may be mixed with the primary
mobilising fluid.
[0121] A major challenge of injecting catalysts into a reservoir using
prior art is
that due to natural reservoir heterogeneity there is little control over where
the
catalysts will end up in the reservoir and whether they will be exposed to the
right
conditions (temperature, pressure, fluid compositions) that will enable them
to be
effective in upgrading the properties of the hydrocarbons. These facts
combined with
the relatively expensive nature of most catalysts, mean that catalysts are
rarely used
in situ to improve the properties of hydrocarbons before they are produced to
surface.
[0122] An advantage may be that in some embodiments it addresses all of the
disadvantages of using catalyst in situ in the prior art. Firstly, by moving
the injection
point for the mobilising fluids through the reservoir there is much greater
control over
the rate and flux of the injected mobilising fluids in the first place.
Secondly, by
injecting catalysts with the secondary mobilising fluid, a zone of mobilised
hydrocarbons and the catalyst can be created in the reservoir; which is
subsequently
contacted with the primary mobilising fluid as the completion device is moved
through the reservoir, thereby creating the optimal conditions for the
catalyst to
improve the properties of the hydrocarbons in the reservoir.
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[0123] Throughout this specification, a "horizontal well or well bore" is
understood
to refer to a well bore which is largely aligned with the horizontal plane but
which
may have one or more sections which deviate by up to +/- 45 degrees and may
have
a vertical section which may also deviate by up to +/- 45 degrees.
[0124] Another feature of the oil formations that are the target of some
methods
of the present disclosure is that the reservoirs are heterogeneous; that is,
that zones
with different properties exist in the reservoirs. For example, zones of high
or low
permeability; zones which are highly fractured or not highly fractured; zones
of high
or low oil saturation; zones of high or low porosity; zones of high or low
water
saturation; and so forth. In an embodiment, the hydrocarbon bearing
subterranean
formation may be naturally fractured. In an embodiment the hydrocarbon bearing
subterranean formation has been fractured via earlier fracturing operations.
In an
embodiment, the hydrocarbon bearing subterranean formation is unfractured.
[0125] In an embodiment the produced fluids may be produced to surface via
a
conduit in the injection tubing. For example, the injection tubing may consist
of
concentric tubing enabling both the injection of mobilising fluids and the
production of
produced fluids.
[0126] In an embodiment the produced fluids may be produced to surface via
artificial lift, i.e. due to pumping to surface or due to the injection of low
density fluids
(i.e. gases) into the well to lift them to surface. The artificial lift fluids
may be injected
via dedicated tubing placed in the well or may be formed via the injection and
reaction of the mobilising fluids with the in situ hydrocarbons (for example
during in
situ combustion, the reaction of injected air with the hydrocarbons forms
light gases).
[0127] In embodiments, the present invention relates to systems and methods
of
recovering hydrocarbon containing fluids by injecting mobilising fluid via an
apparatus which is moved through the horizontal well bore, in time and space;
and
specifically enables the injection of mobilising fluids and the production of
reservoir
fluids to/from different regions of the reservoir at different times.
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[0128] According to a third aspect there is provided a method to recover
hydrocarbons from a subterranean formation, wherein the formation is
intersected by
at least one well-pair comprising a first generally horizontal well and a
second
generally horizontal well situated near the first well, the method comprising
the steps
of:
injecting a mobilising fluid into the first horizontal well at a first
location to
create a first mobilised zone, the first mobilised zone including a mixture of
mobilised
fluids including injected mobilising fluid and mobilised hydrocarbons;
withdrawing via the second horizontal well the mixture of mobilised fluids
that flow out of the hydrocarbon bearing subterranean formation as a produced
fluid;
and
changing the location of injection of mobilising fluid and repeating steps a)
and b) one or more times so as to inject mobilising fluid into the well at one
or more
subsequent further location(s) remote from the first location to create one or
more
subsequent further mobilised zone(s) remote from the first mobilised zone.
[0129] The description in relation to the single well aspects above can
apply to
the well pair aspect, and visa versa, unless the context makes clear
otherwise.
[0130] The completion assembly in the first and or second wells may
comprise of
any of the aforementioned completion assemblies disclosed as part of the first
and
second aspects, and visa versa. Specifically, any of the completion assemblies
described in Figures 1 to 16 may be used in the single well and or the well
pair.
[0131] The means of injecting the mobilising fluid can be a completion
assembly
in the first well. The means of withdrawing the produced fluid can be a
completion
assembly in the second well.
First well
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[0132] An advantage of using a moveable completion assembly to inject
mobilising fluids into the reservoir from the well is that greater precision
can be
possible in the injection of the mobilising fluid. In particular, by using the
completion
assembly in the methods as described herein, the injection of the mobilising
fluid(s)
can be focused over only a portion of the well bore and hence the flux of
mobilising
fluids into the reservoir may be controlled to ensure optimum use of the
mobilising
fluids. Typically, in enhanced oil recovery operations, achieving a high ratio
of
hydrocarbons to the mobilising fluids is desirable. In many enhanced oil
recovery
methods controlling the flux of the injected mobilising fluids is critical to
achieving the
conditions required to mobilise the maximum amount of hydrocarbons from the
reservoir.
[0133] By focusing the injection of mobilising fluids onto specific zones
of the
reservoir at any one time, the operation can in some embodiments use the
optimum
flux of mobilising fluids to maximise hydrocarbon recovery and maximise the
ratio of
hydrocarbons produced to mobilised fluids injected. Given that most reservoirs
are
heterogeneous in nature, the optimum operating conditions may then be selected
for
each zone of the reservoir, as the location(s) of the injected mobilising
fluids are
moved through the reservoir.
[0134] By moving the location of the injection of mobilising fluids along
the
horizontal well bore of the first well, operators can attempt to achieve: i)
an efficient
use of the mobilising fluids, ii) sustained production of hydrocarbon fluids
and iii) high
hydrocarbon recovery factor. Each of these parameters directly relates to the
economic performance of an enhanced oil recovery operation
[0135] The mobilising fluids can be injected into the hydrocarbon bearing
reservoir through at least one opening in the tubing. If the tubing is
arranged in a well
liner, the mobilising fluid can then pass through an open area such as
perforations in
the liner. In the reservoir, a zone of mobilised hydrocarbons is therefore
created,
which will comprise naturally occurring hydrocarbons and the mobilising
fluids; and
or the products of any physical and chemical interactions which occur between
them.
The zone of mobilised hydrocarbons is a zone located in the vicinity of the
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completion assembly of the first well from which mobilising fluids are
injected to the
reservoir.
[0136] The resulting mixture of fluids from the mobilised zone can be
referred to
as the produced fluids. The produced fluids from the zone of mobilised
hydrocarbons
may flow via gravity, pressure and or other means through the liner of the
completion
assembly of the second well, as described below, and may enter the completion
tubing. From there the produced fluids may travel to the heel of the well and
be
produced to surface via a pump and production tubing.
[0137] The completion tubing can be a concentric tubing comprising an inner
tube and an outer tube. The tubing can comprise at least one opening in the
form of
a first series of apertures. The first series of apertures can be in fluid
communication
with the inner tube. The tubing can comprise a further series of apertures
spaced
along the length of the tubing. The further series of apertures can be in
fluid
communication with the outer tube. The first series of apertures can be
towards the
tip of the tubing. The further series of apertures can be remote from the tip.
[0138] In an embodiment, the apertures are arranged on a completion device.
There can be more than one completion device installed onto the completion
tubing.
The advantage of the completion device is that is can integrate all of the
required
functions in one device and may be readily installed onto and uninstalled from
the
completion tubing from the rig equipment at surface. By having a standard
completion device, multiple may be easily installed onto the completion tubing
as it is
positioned into the wellbore. The completion device may also incorporate
common
features of existing oil and gas completions such as monitoring
instrumentation,
inflow/outflow devices to control the rate of injection/production of fluids
to/from the
reservoir, and sealing devices and safety devices such as quick-disconnect
mechanisms. An injection completion device can be installed on the completion
assembly in the injection well.
[0139] The apertures can be any desired pattern of open area; for example
slots,
holes or even just an open end of the tubing. The first series of apertures
can
comprise a cluster of 2, 3, 4, 5, 6, 7, 8, 9, or 10 apertures each of about 5,
10, 15,
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20, 25 mm in diameter. There can be more than one set of first series of first
apertures in the completion tubing, each set spaced apart from one another.
The first
series of apertures can comprise a cluster of 2, 3, 4, 5, 6, 7, 8, 9, or 10
apertures
each of about 5, 10, 15, 20, 25 mm in diameter. There can be more than one set
of
further series of apertures in the completion tubing, each set spaced apart
from
another.
[0140] The apertures in the completion tubing can deliver the mobilising
fluid into
the horizontal well and then into the reservoir. If the tubing is a concentric
tubing,
there can be more than one mobilising fluid. The first series of apertures can
deliver
a first mobilising fluid, and the further series of apertures can deliver a
second
mobilising fluid
[0141] Where there is more than one mobilising fluid, each mobilising fluid
can
be injected into the reservoir at a different location. At or near each
injection location
one or more sealing devices can be installed to form a seal between the
completion
tubing and the liner. The one or more seals can assist in ensuring that the
injected
mobilising fluid is injected with the correct flux into the reservoir at the
required
location(s) and does not redistribute along the length of the horizontal
injection well,
thereby reducing the average flux into the reservoir.
[0142] In an embodiment, the completion assembly in the first well can
comprise
of completion tubing and completion devices, which are well known in the art.
For
example, sliding sleeve devices are well known completion devices in the prior
art
which generally can only convey one fluid at a time, to or from the reservoir,
which
may be sufficient for the purposes of the first well. For example, out flow
devices
may be installed in combination with the completion tubing and sliding sleeve
devices.
[0143] When the hydrocarbons in the zone of mobilised hydrocarbons have
been
produced, the location of the injection of the mobilising fluids may be moved
longitudinally along the horizontal well bore of the first well, to enable the
mobilisation of hydrocarbons from a new portion of the reservoir.
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[0144] In an embodiment, the step of changing the location of the injection
of
mobilising fluid in the first well can comprise of moving a sliding sleeve in
a
completion device to open apertures, thereby enabling mobilizing fluid to
enter the
reservoir at a new location along the well bore.
[0145] In an embodiment, the step of changing the location of the injection
of
mobilising fluid in the first well can comprise of moving a sliding sleeve in
a
completion device to close apertures, thereby disabling mobilizing fluid to
enter the
reservoir at an old location along the well bore.
[0146] In an embodiment, the step of changing the location of the injection
of
mobilising fluid in the first well can comprise of moving the completion
tubing, and if
installed, the completion devices, longitudinally along the horizontal well
bore,
thereby enabling the mobilizing fluid to enter the reservoir at a new location
along the
first well bore.
[0147] In an embodiment the mobilising fluid may be injected continuously.
In an
embodiment the mobilising fluid may be injected discontinuously, for example
as per
cyclic processes (such as "huff and puff") and/or as per sequential processes
(such
as water-alternating-gas (WAG) injection).
Second well
[0148] The second well will be located within the vicinity of the first
well. The
relative location of the first and second wells will depend on the nature of
the
enhanced oil recovery method and the nature of the reservoir, in particular
the
viscosity of the hydrocarbon fluids and the permeability of the reservoir.
[0149] The horizontal section of the second well may be located at a higher
or
lower elevation (depth) relative to the first well. The second well may be
located
deeper than the first well when it is desirable to enhance the gravity drive
mechanism to increase flow of produced fluids to the second well. The second
well
may be located shallower than the first well, when some of the produced fluids
have
a lower relative density, for example to extract gaseous vapours from the
reservoir or
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to extract oil from a layer above a water saturated zone. Most often, the
first and
second well will be located at approximately the same elevation (depth).
[0150] The lateral distance between the first well and second well may be
between a few tens of metres and a few thousand metres. Typically, the
distance
between the wells will be in the range of from about 50 and about 500 metres,
preferably about 50 to about 200 metres. However, in general, the lateral
distance
between the wells will be chosen with regards to the reservoir properties, the
type of
enhanced oil recovery methods being used and surface constraints. For example,
offshore wells will likely be spaced further apart than onshore wells.
[0151] In an embodiment, the completion assembly in the second well can
comprise of completion tubing and completion devices, which are well known in
the
art. For example, sliding sleeve devices are well known completion devices in
the
prior art which generally can only convey one fluid at a time, to or from the
reservoir,
which may be sufficient for the purposes of the second well. For example, in
flow
devices may be installed in combination with the completion tubing and sliding
sleeve devices.
[0152] In an embodiment, as the location of the injection of mobilizing
fluid is
changed in the first well, the location of the production of produced fluids
from the
reservoir may be changed in the second well.
[0153] In an embodiment, the step of changing the location of the
production
fluids in the second well can comprise of moving a sliding sleeve in a
completion
device to open apertures, thereby enabling produced fluids to enter a conduit
in the
completion device from the reservoir at a new location along the well bore.
[0154] In an embodiment, the step of changing the location of the produced
fluids
in the second well can comprise of moving a sliding sleeve in a completion
device to
close apertures, thereby disabling produced fluids to enter a conduit in the
completion device from the reservoir at an old location along the well bore.
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[0155] In an embodiment, as the completion tubing in the first well is
moved, the
completion tubing in the second well can be moved. The tubings can be moved at
substantially the same time. The tubings can be moved over substantially the
same
distances.
[0156] By moving the location of the injection zone along the horizontal
section of
the first well, operators can attempt to achieve: i) an efficient use of the
mobilising
fluids, ii) sustained production of hydrocarbon fluids from the second well
and iii) high
hydrocarbon recovery factor for the reservoir. Each of these parameters
directly
relates to the economic performance of an enhanced oil recovery operation.
[0157] The mobilising fluids can be withdrawn from the hydrocarbon bearing
reservoir through at least one opening in the tubing. If the tubing is
arranged in a well
liner, the mobilising fluid can pass through an open area such as perforations
in the
liner. In the reservoir, a zone of mobilised hydrocarbons is created, which
will
comprise naturally occurring hydrocarbons and the mobilising fluids; and or
the
products of any physical and chemical interactions which occur between them.
The
zone of mobilised hydrocarbons is a zone located in the vicinity of the
completion
assembly from which mobilising fluids and produced fluids are injected to and
extracted from the reservoir, respectively.
[0158] The resulting mixture of fluids from the mobilised zone can be
referred to
as the produced fluids. The produced fluids from the zone of mobilised
hydrocarbons
may flow via gravity, pressure and or other means back through the liner and
may
enter the completion tubing. From there the produced fluids may travel via the
second well to the heel of the well and be produced to surface via a pump and
production tubing.
[0159] The completion tubing in the second well can be a concentric tubing
comprising an inner tube and an outer tube. The tubing can comprise at least
one
opening in the form of a first series of apertures. The first series of
apertures can be
in fluid communication with the inner tube. The tubing can comprise a further
series
of apertures spaced along the length of the tubing. The further series of
apertures
can be in fluid communication with the outer tube. The first series of
apertures can
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be towards the tip of the tubing. The further series of apertures can be
remote from
the tip.
[0160] In an embodiment, the apertures are arranged on a completion device.
There can be more than one completion device installed onto the completion
tubing.
The completion device may also incorporate common features of existing oil and
gas
completions such as monitoring instrumentation, inflow/outflow devices to
control the
rate of injection/production of fluids to/from the reservoir, and sealing
devices and
safety devices such as quick-disconnect mechanisms. A production completion
device can be installed on the completion assembly in the production well.
[0161] The apertures can be any desired pattern of open area; for example
slots,
holes or even just an open end of the tubing. The first series of apertures
can
comprise a cluster of 2, 3, 4, 5, 6, 7, 8, 9, or 10 apertures each of about 5,
10, 15,
20, 25 mm in diameter. There can be more than one set of first series of first
apertures in the completion tubing, each set spaced apart from one another.
The first
series of apertures can comprise a cluster of 2, 3, 4, 5, 6, 7, 8, 9, or 10
apertures
each of about 5, 10, 15, 20, 25 mm in diameter. There can be more than one set
of
further series of apertures in the completion tubing, each set spaced apart
from
another.
[0162] The apertures in the completion tubing can receive and withdraw the
mobilising fluid into the horizontal well from the reservoir.
[0163] When the hydrocarbons in the zone of mobilised hydrocarbons have
been
produced, the location of the completion tubing may be moved longitudinally
along
the horizontal well bore, to enable the mobilisation of hydrocarbons from a
new
portion of the reservoir.
[0164] In an embodiment the second well may be fitted with inflow control
devices to manage the pressure drop through the reservoir and along the length
of
the horizontal section of the well. The inflow devices may be installed on the
completion tubing.
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[0165] In an embodiment, the second well may be an open completion or a
well
liner without any completion tubing. In this case, the fluids enter the second
well at
locations along the horizontal without any physical intervention.
[0166] In an embodiment the produced fluids may be produced continuously.
In
an embodiment the produced fluids may be produced discontinuously, for example
as per cyclic processes (such as "huff and puff") and/or as per sequential
processes
(such as water-alternating-gas (WAG) injection).
[0167] In an embodiment, an upgrading device is provided in the path of the
produced fluid so as to upgrade the produced fluid as it is withdrawn through
the
tubing. The upgrading device can be a physical device, a material, a mixture
of
materials and/or a sequence of materials which improves the quality of the
produced
hydrocarbon fluids from the reservoir.
[0168] In an embodiment, the quality of the produced fluids is monitored.
Monitoring of the quality of the produced fluids can provide an indicator of
how to
move the completion through the reservoir. A low ratio of hydrocarbons to
mobilising
fluids may indicate that the frequency and/or distance which the completion
tubing
(and associated completion device) is moved should be increased. A high ratio
of
hydrocarbons to mobilising fluids may indicate that the frequency and/or
distance
which the completion device is moved should be decreased.
[0169] Therefore, in some embodiments the method can further comprise the
steps of:
monitoring the produced fluid from each of the mobilised zones to
determine the ratio of used mobilising fluid and mobilised hydrocarbons in the
produced fluid;
selecting or otherwise adjusting the frequency of the change in the
location of injection of mobilising fluid and or the distance between the
first location
and the one or more further locations depending on the monitored ratio.
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[0170] When a low ratio of hydrocarbons to mobilising fluids is reached the
frequency and/or distance which the tubing is moved should be increased. When
a
high ratio of hydrocarbons to mobilising fluids is reached the frequency
and/or
distance which the tubing is moved should be decreased. The ratio will depend
on
the type of mobilising fluid used; each fluid will have different properties.
Also the
ratio will depend on the reservoir.
[0171] The combination of moving the injection location in the first well
and
monitoring the produced fluids from the second well can alleviate the need to
individually monitor and control the influx of produced fluids from discrete
regions of
the reservoir in the production well.
[0172] In an embodiment the produced fluids may be produced to surface via
artificial lift, i.e. due to pumping of the fluids or due to the injection of
low density
fluids (ie. gases) into the well to lift them to surface. The artificial lift
fluids may be
injected via dedicated tubing placed in the well or may be formed via the
injection
and reaction of the mobilising fluids with the in situ hydrocarbons (for
example during
in situ combustion, the reaction of injected air with the hydrocarbons forms
light
gases).
[0173] It should also be recognised that while the discussion above refers
to a
well pair with a first well (the injection well) and a second well (the
production well),
in some embodiments more than one injection well can be used with a single
production well; and in some embodiments more than one production well can be
used with a single injection well. Further, in some embodiments the method may
be
applied to patterns of wells, wherein any suitable ratio of injection wells to
production
wells can be applied.
[0174] The discussion below refers to the completion assembly of the first
well
and the completion assembly of the second well unless the context makes clear
otherwise.
[0175] The step of moving of the tubing in either the first well or the
second well
can comprise retracting the tubing. The step of moving of the tubing can
comprise
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advancing the tubing. The step of retracting the tubing can be undertaken by
removal of tubing sections. The step of retracting the tubing can be by
winding up
the tubing. The step of advancing the tubing can be undertaken by addition of
tubing
sections. The step of advancing the tubing can be by winding out the tubing
from a
coil.
[0176] The step of changing the location of injection can be changing the
injection point along the length of the tubing.
[0177] In an alternative, rather than move the completion assembly, there
can
instead be a mechanism by which various apertures in the completion assembly
are
openable and closable so as to cause the change in the location of the
injection of
mobilising fluid. Thus, in the step c), the step is undertaken by changing the
apertures in the completion assembly through which mobilising fluid is
injected. The
change in the apertures used can be sequential, so there is effectively a
front of
mobilising fluid movement injected into the formation over time. The apertures
can
be openable and closable by any means.
[0178] In an embodiment the apertures can be opened and closed using
sliding
sleeve devices which are well known in the industry. The sliding sleeve
devices may
be activated using pressure, dropped balls of different sizes, RFID tags,
hydraulic
control lines, slick lines, coiled tubing or any other suitable means. As will
be
appreciated by those skilled in the art, when a sliding sleeve device is used,
a well
liner may not be present or its functionality (eg. to prevent sand inflow) can
be
incorporated into the sliding sleeve device itself.
[0179] In an embodiment, the completion assembly can comprise of a number
of
completion devices, whereby each completion device has apertures that can be
opened and closed, thereby enabling the injected fluids to be injected at one
location
along the horizontal well bore at one time, and at another location at another
time.
Similarly, the produced fluids can be produced from one location at one time
and
another location at another time.
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[0180] The completion devices can comprise of sliding sleeves that may be
moved to open and close the apertures for the injected fluids and for the
produced
fluids. In an embodiment, the sliding sleeves may be operated using any
conventional means, including coiled tubing or wireline tools to latch on to
the sleeve
and move its position, the use of drop balls, the use of hydraulic actuators
and any
other method known in the art.
[0181] In an embodiment the completion device can comprise of a conduit for
the
injected fluid and a conduit for the produced fluid.
[0182] In an embodiment the completion assembly can comprise of a number of
completion devices connected directly together. In an embodiment the
completion
devices can be connected together using standard tubings.
[0183] In an embodiment, the new location of the injection point in the
completion
assembly, may overlap with its old position, thereby creating an overlap
between the
old and new location of the zone of mobilised hydrocarbons. Generally, it is
preferable to ensure that the zone of mobilised hydrocarbons formed by
operation at
successive positions of the completion assembly overlap. This may ensure that
there
is a zone of sufficient permeability to inject the mobilising fluids. It may
also help to
ensure a high recovery factor for the hydrocarbons, as all of the reservoir is
contacted successively with mobilising fluids.
[0184] The mobilising fluid can be selected from one or more of steam,
oxidants
(oxygen containing fluids), solvents, carbon dioxide, light hydrocarbons such
as
methane, ethane, propane and butane, water and nitrogen and any other fluids
usually used for the same purpose. Where there is a first mobilising fluid and
a
second mobilising fluid, the two fluids can be the same or different from one
another.
[0185] In some applications, for example recovery of bitumen and very heavy
oils, a zone of mobilised hydrocarbons may need to be present between the
first well
and the second well, before the system of the second aspect can be applied.
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[0186] In an embodiment the zones of mobilised hydrocarbons between the
first
well and second well may be generated by any method well known in the field.
For
example, steam circulation is often used in bitumen recovery to mobilise
bitumen
between an injection well and a production well.
[0187] In an embodiment, the application of the third aspect in a first and
second
well, may follow an earlier operation where each well has been operated with
injection and production according to the first and or second aspects.
[0188] An advantage of this sequence of operations is that zones of
mobilised
hydrocarbons will have already been created, by the earlier single well
operations,
and these zones may overlap, thereby creating a continuous or nearly
continuous
zone of mobilised hydrocarbons between the first well and the second well.
[0189] The presence of continuous or nearly continuous zones of mobilised
hydrocarbons may be necessary to establish injection from the first well and
production from the second well in some reservoirs.
BRIEF DESCRIPTION OF THE DRAWINGS
[0190] Embodiments of the invention and other embodiments will now be
described with reference to the non-limiting drawings which are exemplary
only. The
description in relation to any one of the Figures can be applied to any of
other of the
Figures unless the context makes clear otherwise.
[0191] Figure 1 is a side section view of a portion of hydrocarbon-bearing
subterranean formation illustrating certain aspects using a predominately
horizontal
well.
[0192] Figure 2 is a side section view of a portion of hydrocarbon-bearing
subterranean formation illustrating certain aspects using a predominately
horizontal
well.
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[0193] Figure 3 illustrates an embodiment wherein the moveable well
completion
incorporates a single tubing string and is configured for single zone
injection of the
mobilising fluids and the recovery of hydrocarbons in the annulus between the
well
liner and tubing string.
[0194] Figure 4 illustrates an embodiment wherein the moveable well
completion
incorporates a concentric tubing string and is configured for single zone
injection of
the mobilising fluids and the recovery of hydrocarbons in the inner tubing of
the
concentric tubing string. An upgrading material is installed to improve the
properties
of the produced hydrocarbon fluids as they flow back to surface.
[0195] Figure 5 illustrates an embodiment wherein the moveable well
completion
incorporates a concentric tubing string and is configured for injecting a
primary and
secondary mobilising fluid and the recovery of hydrocarbons in the annulus
between
the well liner and tubing string.
[0196] Figure 6 illustrates an embodiment wherein the moveable well
completion
incorporates a concentric tubing string and is configured for multiple zone
injection of
a single mobilising fluid and multiple zone recovery of the produced
hydrocarbons
the annulus of the concentric tubing string.
[0197] Figure 7 illustrates an embodiment showing two adjacent
predominately
horizontal wells each of which is configured for multiple zone injection and
multiple
zone recovery of the hydrocarbons from the reservoir. Although two wells are
shown,
each well is operating as a single injector/producer.
[0198] Figure 8 is a side section view of a portion of hydrocarbon-bearing
subterranean formation illustrating certain aspects using a predominately
horizontal
well.
[0199] Figure 9 is a side section view of a portion of hydrocarbon-bearing
subterranean formation illustrating certain aspects using a predominately
horizontal
well.
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[0200] Figure 10 illustrates a side view of an embodiment wherein the
completion
device incorporates an eccentrically arranged sliding sleeve device and
completion
tubings that enable it to be connected to other tools.
[0201] Figure 11 illustrates cut-away views of the positions of components
of an
embodiment wherein the completion device incorporates an eccentrically
arranged
sliding sleeve device.
[0202] Figure 12 illustrates a view of an embodiment wherein the completion
device incorporates a concentrically arranged sliding sleeve device and the
sleeve is
positioned so that no flow occurs.
[0203] Figure 13 illustrates a view of an embodiment wherein the completion
device incorporates a concentrically arranged sliding sleeve device and the
sleeve is
positioned so that flow can occur between the inner annulus and the outside of
the
completion device (reservoir).
[0204] Figure 14 illustrates a view of an embodiment wherein the completion
device incorporates a concentrically arranged sliding sleeve device and the
sleeve is
positioned so that flow can occur between the outer annulus and the outside of
the
completion device (reservoir).
[0205] Figure 15 is a side section view of a portion of hydrocarbon-bearing
subterranean formation illustrating certain aspects using a predominately
horizontal
well.
[0206] Figure 16 is a conceptual drawing of the configuration and
sequencing of
completion devices in a well bore.
[0207] Figure 17 shows two adjacent predominately horizontal wells, one
well
configured for multiple zone injection of mobilising fluids and the other well
configured for multiple zone recovery of the hydrocarbons from the reservoir,
wherein the hydrocarbons are transported to surface in production tubing
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[0208] Figure 18 shows two adjacent predominately horizontal wells, one
well
configured for multiple zone injection of mobilising fluids and the other well
configured for recovery of hydrocarbons from the reservoir along the length of
the
horizontal, wherein the hydrocarbons are transported to surface using a pump
and
production tubing.
[0209] Figure 19 shows the moveable well completion incorporating a
concentric
tubing string configured for the injection of a primary and secondary
mobilising fluid
into the hydrocarbon bearing reservoir.
[0210] Figure 20 shows temperature profiles through the reservoir for an
embodiment showing a single point injection for Moving Injection Combustion
Stimulation (MICS) at three different times.
[0211] Figure 21 shows temperature profiles through reservoir for an
embodiment showing a multiple-point injection for Moving Injection Combustion
Stimulation (MICS) at three different times.
[0212] Figure 22 shows a schematic of the computational domain and shows
contours of oil saturation in the reservoir after 10 years of waterflood
enhanced oil
recovery for static and moving injection configurations.
[0213] Figure 23 is a plan view of temperature contours at three different
times
from two adjacent predominately horizontal wells configured for single point
injection
for Moving Injection Combustion Stimulation (MICS).
[0214] Figure 24 is a plan view of temperature contours at three different
times
from two adjacent predominately horizontal wells, where the first well is
configured
for the moving injection of mobilised fluids and the second well is configured
to
produce hydrocarbons from the reservoir.
DESCRIPTION OF EMBODIMENTS
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[0215] Throughout this specification, unless the context requires
otherwise, the
words "comprise"/"include", "comprises"/"includes" and
"comprising"/"including" will
be understood to mean the inclusion of a stated integer, group of integers,
step, or
steps, but not the exclusion of any other integer, group of integers, step, or
steps.
[0216] Any promises made in the present description should be understood to
relate to some embodiments of the invention, and are not intended to be
promises
made about the invention. Where there are promises that are deemed to apply to
all
embodiments of the invention, the right is reserved to later delete those
promises
from the description since there is no intention to rely on those promises for
the
acceptance or subsequent grant of a patent unless the context makes clear
otherwise.
SINGLE WELL
[0217] Referring to Figure 1, there is generally depicted a hydrocarbon
bearing
subterranean formation 6. A generally horizontal well bore 10 is drilled
through the
over burden formation 18 and into the hydrocarbon bearing reservoir 6 using
standard directional drilling techniques. Fractures 20 may exist in the
reservoir 6
and/or overburden 18. Casing 22 extends from the surface to the horizontal
section
of the well. Surface casing 28, which may consist of multiple concentric
tubings, is
installed into the vertical section of the well. The casings and tubings are
connected
together at surface in a wellhead 30 as is common practice. A liner 4 with a
certain
amount of open area is installed into the horizontal section of the well bore
10.
Completion tubing 2 is installed into the well, with a completion device 12 at
its tip.
The completion tubing may be jointed tubing or it may be coiled tubing. The
completion tubing 2 may consist of a single tubing or it may consist of
multiple
tubings, including concentric tubings. Production tubing 24 may be installed
into the
vertical section of the well along with a pump 26. Mobilising fluids 8 are
injected from
surface through the completion tubing 2 and enter into the completion device
12. The
mobilising fluids 8 may exit into the annular space between the completion
device 12
and the liner 4. The mobilising fluids are injected into the hydrocarbon
bearing
reservoir 6 through the open area in the liner 4. In the reservoir 6 a zone of
mobilised
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hydrocarbons 14 is created, which consists of naturally occurring hydrocarbons
and
the mobilising fluids; and the products of any physical and chemical
interactions
which occur between them. The resulting mixture of fluids from the mobilised
zone
are labelled as the produced fluids 16. The produced fluids 16 from the zone
of
mobilised hydrocarbons 14 flow via gravity, pressure and other means back
through
the liner 4 and may enter the annular space between the completion tubing 2
and
liner 4. From there the produced fluids may travel to the heel of the well and
be
produced to surface via a pump 26 and production tubing 24
[0218] The zone of mobilised hydrocarbons 14 is a zone located in the
vicinity of
the completion device 12, from which mobilising fluids 8 and produced fluids
16 are
injected to and extracted from the reservoir, respectively.
[0219] When the hydrocarbons in the zone of mobilised hydrocarbons 14 have
been produced using the completion device, in this embodiment the location of
the
completion device 12 may be moved longitudinally along the horizontal well
bore 10,
to enable the mobilisation of hydrocarbons from a new portion of the
reservoir. The
completion device 12 may be moved into or out of the well bore by adding or
removing one or more joints of tubing, when the completion tubing is jointed;
or by
winding or unwinding the coiled tubing if the completion tubing is coiled.
[0220] In an embodiment, the hydrocarbon bearing subterranean formation 6
may be naturally fractured. In an embodiment the hydrocarbon bearing
subterranean
formation 6 has been fractured via earlier fracturing operations. In an
embodiment,
the hydrocarbon bearing subterranean formation 6 is unfractured.
[0221] In an embodiment in which the tubing in moved, as seen in Figure 2,
the
location of the completion device 112 is moved along the well bore from its
old
position (in Figure 1). In an embodiment as also seen in Figure 2, the new
location of
the completion device 112, may overlap with its old position (in Figure 1),
thereby
creating an overlap between the old and new location of the zone of mobilised
hydrocarbons 114.
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[0222] Generally, it is preferable to ensure that the zone of mobilised
hydrocarbons 114 formed by operation at successive positions of the completion
device 112 overlap. This ensures that there is a zone of sufficient
permeability to
inject the mobilising fluids 108; it also helps to ensure a high recovery
factor for the
hydrocarbons, as all of the reservoir is contacted successively with
mobilising fluids
108.
[0223] Monitoring of the quality of the produced fluids 116 can provide an
indicator of how to move the completion device 112 through the reservoir. A
low ratio
of hydrocarbons to mobilising fluids may indicate that the frequency and/or
distance
which the completion device 112 is moved should be increased. A high ratio of
hydrocarbons to mobilising fluids may indicate that the frequency and/or
distance
which the completion device is moved should be decreased.
[0224] An advantage of using a moveable completion device 112 to inject
mobilising fluids 108 into the reservoir 106 is that greater precision is
possible in the
injection of the mobilising fluid 108. In particular, by using the completion
device 112
the injection of the mobilising fluids 108 can be focused over only a portion
of the
well bore 110 and hence the flux of mobilising fluids 108 into the reservoir
106 can
be controlled to ensure optimum use of the mobilising fluids. In all enhanced
oil
recovery operations achieving a high ratio of hydrocarbons to the mobilising
fluids is
desirable. In many enhanced oil recovery methods controlling the flux of the
injected
mobilising fluids is critical to achieving the conditions required to mobilise
the
maximum amount of hydrocarbons from the reservoir.
[0225] By moving the completion device 112 along the horizontal well bore
110,
operators can achieve: i) an efficient use of the mobilising fluids, ii)
sustained
production of hydrocarbon fluids and iii) high hydrocarbon recovery factor.
Each of
these parameters directly relates to the economic performance of an enhanced
oil
recovery operation
[0226] In an embodiment, multiple completion devices 112 may be installed
onto
the completion tubing 102.
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[0227] In an embodiment the produced fluids 116 may be produced to surface
via a conduit in the injection tubing 102. For example, the injection tubing
may
consist of concentric tubing enabling both the injection of mobilising fluids
108 and
the production of produced fluids 116.
[0228] In an embodiment the produced fluids 116 may be produced to surface
via artificial lift, i.e. due to a pump or due to the injection of low density
fluids (ie.
gases) into the well to lift them to surface. The artificial lift fluids may
be injected via
dedicated tubing placed in the well or may be formed via the injection and
reaction of
the mobilising fluids with the in situ hydrocarbons (for example during in
situ
combustion, the reaction of injected air with the hydrocarbons forms light
gases)
[0229] The details of the completion device 112 and examples of specific
embodiments are provided in Figures 3 to 6 and Figures 10 to 14.
[0230] Referring to Figure 3, there is generally depicted a hydrocarbon
bearing
subterranean formation 206, a generally horizontal section of a well bore 210
and the
completion device 212.
[0231] Mobilising fluids 208 are injected into the completion device 212
and exit
from apertures 242 in the device. The mobilising fluids enter the space
between the
completion device 212 and the liner 204 and are injected into the hydrocarbon
reservoir 206.
[0232] The apertures 242 in the completion device 212 may be any desired
pattern of open area; for example slots, holes or even just an open end of the
tubing.
[0233] The mobilising fluids 208 forms a zone of mobilised hydrocarbons
within
the reservoir, in the vicinity of the completion device 212.
[0234] Produced fluids 216 pass through the liner 204 at locations with
open area
and enter into the annulus between the completion device 212 and the liner
204; and
then flow to surface.
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[0235] In order to prevent, or at least reduce, the propensity for the
mobilising
fluids 208 to bypass the reservoir 206 and return to surface via the annulus,
one or
more sealing devices 240 are installed to form a seal between the completion
device
212 and the liner 204; and thereby prevent a direct connection from forming
between
the injection apertures 242 and the production annulus.
[0236] Ideally, the sealing devices 240 would be positioned at locations
such that
they seal with blank sections of the liner 204, as opposed to sections of the
liner 204
containing open area. This is possible, if the liner 204 and completion device
212 are
designed and installed together. However, in general, when the completion
device
212 is used in an old well, with a typical pattern of open area used in
liners, then the
sealing devices 240 will necessarily need to seal against areas of the liner,
containing some open area.
[0237] The sealing devices 240 are designed to i) create a seal between the
completion device 212 and the liner 204, and ii) allow the completion device
212 to
be moved into and out of the well bore 210. The sealing devices should also be
designed for the well bore conditions experienced during operation; for
example, the
relevant temperature, pressure, fluid compositions and the presence of
reservoir
materials such as sand and rock in addition to hydrocarbons.
[0238] In an embodiment, sealing devices 240, may also be installed at the
end
of the completion device 212 so that the mobilising fluids 208 can only pass
through
a specific zone of the liner 204 and into the reservoir 206.
[0239] If thermal enhanced oil recovery operations are used, then the
sealing
devices 240 must be able to withstand the high operating temperatures. When
using
solvents as the mobilising fluid temperatures up to 200 C may be present;
when
using steam as the mobilising fluid temperatures up to 300 C may be present;
while
during in situ combustion temperatures up to 600 C may be present. When such
high temperatures are present a metal to metal seal may be preferred. In
order, to
allow movement of the seal, some degree of leakage from the seal may be
acceptable and/or a necessary compromise to make.
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[0240] If low temperature (less than 200 C) enhanced oil recovery
operations
are used then the materials used for the sealing devices 240 may be selected
from a
large range of generally available materials, such as elastomers. The sealing
devices 240 may be inflatable devices. In general, the sealing function of the
sealing
devices 240 should not be triggered by a reaction with the mobilising fluids
208 or
the produced fluids 216, since these methods of sealing will likely prevent
the
subsequent movement of the sealing devices 240.
[0241] In an embodiment, different mobilising fluids 208 may be injected in
a
sequence. For example, when the mobilising fluid 208 is an oxidant, water may
be
injected in sequence with the oxidant. During water injection into the
completion
device 212, the production of hot produced fluids 216 due to the combustion
process, will heat the injected water turning it into steam, absorbing a large
amount
of energy. Hence, by injection a sequence of mobilising fluids 208 of oxidant
and
then water, the temperature of the completion device 212 and well liner 204
can be
controlled to temperatures which ensure the mechanical integrity of the
materials
used and are below about 500 C, and preferably below about 300 C. At the
same
time, both oxygen and steam are injected into the formation 206, to mobilise
the
hydrocarbons.
[0242] The liner may have any arrangement of open area, including slots,
holes,
perforations or permeable meshes, such as wire wraps, installed in any manner.
In
many applications, liners 204, have slots 244 manufactured into them.
[0243] Referring to Figure 4, which shows an embodiment for the completion
device 312 using a concentric tubing string arrangement, which enables the
injection
of the mobilising fluids 308 and the production of produced fluids 316 (and
upgraded
produced fluids 317) to be controlled via a single tubing string.
[0244] A generally horizontal well bore 310 is drilled into the hydrocarbon
bearing
reservoir 306 using standard directional drilling techniques. A liner 304 with
a certain
amount of open area is installed into the well bore 310. The completion device
312
uses a concentric tubing arrangement. Mobilising fluids 308 are injected
through the
annulus 348 formed between the outer and inner tubings and exit from apertures
342
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into the annulus between the completion device 312 and the liner 304. The
mobilising fluids are injected into the hydrocarbon bearing reservoir 306
through the
open area in the liner 304. In the reservoir 306 a zone of mobilised
hydrocarbons is
created, which consists of naturally occurring hydrocarbons and the mobilising
fluids;
and the products of any chemical and physical interactions which occur between
them. The resulting mixture of fluids from the mobilised zone are labelled as
the
produced fluids 316. The produced fluids 316 from the zone of mobilised
hydrocarbons flow via gravity, pressure and other means back through the liner
304
and enter the space around and ahead of the completion device 312 in the well
bore
310. The produced fluids 316 re-enter the completion device 312 through
apertures
346.
[0245] In order to prevent, or at least reduce, the propensity for the
mobilising
fluids 308 to bypass the reservoir 306 and return to surface via the annulus,
one or
more sealing devices 340 are installed to form a seal between the completion
device
312 and the liner 304; and thereby prevent a direct connection from forming
between
the injection apertures 342 and the production apertures 346.
[0246] Inside the completion device 312, an upgrading device 349 may be
present. The upgrading device 349 may be used to upgrade the produced fluids
316
to higher quality; thereby becoming upgraded produced fluids 317.
[0247] When the mobilising fluid 308 is an oxidant, the produced fluids
316, are
expected to be at temperatures between 250 and 600 C. These temperatures are
sufficient to crack medium and heavy oils and bitumen to produce lighter oil
components. Under these conditions, the use of a catalyst in the upgrading
device
349 can improve the properties of the produced fluids. The use of catalyst(s)
as
upgrading material(s) is therefore beneficial.
[0248] Hydrotreating and hydrocracking catalysts may be used in the
upgrading
device 349. Common catalyst materials for hydroprocessing include
CoMo/alumina,
NiMo/alumina and others.
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[0249] When upgrading hydrocarbon fluids at temperature and pressure and
with
catalysts, it is well known that the addition of hydrogen or hydrogen donor
solvents
can greatly improve the upgrading process. In an embodiment, hydrogen or
hydrogen donor solvents may be injected upstream of the upgrading material via
a
hydrogen injection tubing (not shown) to improve the upgrading of the
hydrocarbon
fluids in the upgrading device 349.
[0250] In prior art, such as US Patent 6,412,557 B1 and US Patent 7,909,097
B2, an upgrading catalyst is installed into the well liner, which makes
installation of
the liner much more difficult during well construction, raising costs; and the
contact of
the produced fluids with the catalyst is limited; reducing the degree of
upgrading. In
addition, as only a small volume of the produced fluids come into contact with
each
volume of catalyst; large volumes of catalyst are installed into the liner
with poor
utilisation. The major advantages of the design shown in Figure 4 over the
prior-art is
that: i) catalyst in the upgrading device 349 can be installed and removed
from the
well bore 310, and can therefore be replaced if required, ii) as the
completion device
312 is moved through the reservoir 306, the catalyst is automatically exposed
to all
of the produced fluids 316, making efficient use of the catalyst volume and
iii) the
weighted hourly space velocity (WHSV) of the fluids traversing the catalyst
bed can
be controlled and optimised by the design of the upgrading device 349.
[0251] In processes such as in situ combustion, residual oxygen in the
produced
gases can lead to the presence of flammable and/or explosive mixtures which
present safety problems; especially in surface facilities. The upgrading
device 349
can be designed to react with residual oxygen in the produced fluids 316 to
ensure
that no residual oxygen is present in the produced fluids 317. Various
catalysts are
available to reduce the free oxygen content in produced gases and liquids.
[0252] The produced fluids 316 or the upgraded produced fluids 317 when an
upgrading device is present are produced to surface via the inner tubing
string
formed within the concentric tubing strings of the completion device 312.
[0253] A major advantage of the embodiment shown in Figure 4 is that the
mobilising fluids 308 and the produced fluids 316 travel to/from the reservoir
via
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dedicated conduits and do not travel in the annulus formed with the liner 304.
Fluids
travelling along the annulus formed between the tubing and the liner 304 may
interact with the reservoir 306 in ways which are undesirable due to the open
area in
the liner 304.
[0254] In an embodiment the configuration of the tubings may be reversed;
so
that mobilising fluids 308 are injected into the inner tubing of the
completion device
312 and exit from apertures 346 and produced fluids 316 are produced from the
annulus 348 formed between the outer and inner tubing of the completion device
312. In this embodiment the upgrading device 349 would be placed in the
annulus
348 between the inner and outer tubings
[0255] In an embodiment, a cross-over section of tubing may be fitted to
the
tubing on which the completion device 312 is installed, to enable the conduits
carrying injected and produced fluids to be swapped between the vertical and
horizontal sections of the well bore.
[0256] The optimal configuration of the tubings and of the primary
direction of
movement of the completion device 312 in the well bore 310 is dependent upon
many factors including the reservoir 306 properties, the nature of the
enhanced oil
recovery method and the type of mobilising fluids 308 being injected into the
reservoir 306.
[0257] In the case of thermal enhanced oil recovery using steam injection
and/or
in situ combustion, in which the mobilising fluid 308 is steam or an oxidant,
the zone
of mobilised hydrocarbons may reach high temperatures (200 to 600 C) and the
produced fluids 316 may be hot (> 100 C), it is advisable that the produced
fluids
316 are captured via apertures 346 located at one end of the completion device
312;
and that the primary direction of travel of the completion device 312 within
the well
bore 310 is in the same direction as the produced fluids 316 within the
tubings. This
configuration ensures that the production zone in the vicinity of the liner
304 is ahead
of the completion device 312, and so any damage to liner 304 from overheating
or
excessive sand production does not interfere with the performance of the
sealing
devices 340. The sealing devices 340 generally operate better at ambient
reservoir
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temperatures (between 20 and 100 C) and when the liner 304 geometry and
integrity is maintained and when there is little or no sand build up. This
configuration
(as shown in Figure 4) also has the advantage that any hydrocarbons draining
from
previously swept regions of the reservoir 306 into the well bore 310 may still
be
collected and produced to surface.
[0258] When the hydrocarbons in the zone of mobilised hydrocarbons have
been
produced using the completion device 312, the location of the completion
device 312
may be moved longitudinally along the horizontal well bore 310, to enable the
mobilisation of hydrocarbons from a new portion of the reservoir. The
completion
device 312 may be moved into or out of the well bore by adding or removing one
or
more joints of tubing, when the completion tubing is jointed; or by winding or
unwinding the coiled tubing if the completion tubing is coiled.
[0259] Generally, it is preferred that the zones of mobilised hydrocarbons
formed
successively by moving the completion device 312 along the well bore 310,
overlap.
[0260] In an embodiment the completion device 312 is moved a distance equal
to
the distance between adjacent sealing devices 340.
[0261] In an embodiment, the completion device 312 is moved a distance
equal
to the distance between the apertures 342 and apertures 346, such that the new
location of the apertures 346 is at the old location of the apertures 342 when
the
completion device 312 is retracted from the well bore 310; or the location of
the
apertures 342 is at the old location of the apertures 346 when the completion
device
312 is pushed into the well bore 310.
[0262] Referring to Figure 5, which shows an embodiment for the completion
device 412 using a concentric tubing string arrangement, which enables the
injection
of a primary mobilising fluid 408 and a secondary mobilising fluid 450 and the
production of produced fluids 416 in the annulus between the completion device
412
and the liner 404.
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[0263] A generally horizontal well bore 410 is drilled into the hydrocarbon
bearing
reservoir 406 using standard directional drilling techniques. A liner 404 with
a certain
amount of open area is installed into the well bore 410. The completion device
412
uses a concentric tubing arrangement.
[0264] Primary mobilising fluids 408 are injected through the inner tubing
of the
concentric tubing of the completion device 412. The primary mobilising fluids
408 exit
from apertures 442 into the annulus between the completion device 412 and the
liner
404. The primary mobilising fluids 408 are injected into the hydrocarbon
bearing
reservoir 406 through the open area in the liner 404.
[0265] Secondary mobilising fluids 450 are injected through the annulus
formed
between the outer and inner tubings and exit from apertures 446 into the
annulus
between the completion device 412 and the liner 404. The secondary mobilising
fluids 450 are injected into the hydrocarbon bearing reservoir 406 through the
open
area in the liner 404.
[0266] In the reservoir 406 a zone of mobilised hydrocarbons is created,
which
consists of naturally occurring hydrocarbons and the primary and secondary
mobilising fluids; and the products of any chemical and physical interactions
which
occur between them. An intermediate mixture of fluids 452 is formed from the
interaction of the primary mobilising fluids 408 and the naturally occurring
hydrocarbons. A resulting mixture of fluids, is formed from the interaction of
the
intermediate fluids 452 and the secondary mobilising fluids 450 forming the
produced
fluids 416. The produced fluids 416 from the zone of mobilised hydrocarbons
flow via
gravity, pressure and other means back through the liner 404 and enter the
annular
space between the completion device 412 and the liner 404, from which they are
produced to surface.
[0267] In order to prevent, or at least reduce, the propensity for the
primary
mobilising fluids 408 and secondary mobilising fluid 450 to bypass the
reservoir 406
and return to surface via the annulus, one or more sealing devices 440 are
installed
to form a seal between the completion device 412 and the liner 404; and
thereby
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prevent a direct connection from forming between the apertures 442,446 and the
annulus.
[0268] In an embodiment the configuration of the tubings may be reversed;
so
that primary mobilising fluids 408 are injected into annulus 448 formed
between the
inner and outer tubing of the completion device 412 and the secondary
mobilising
fluids 450 are injected into the inner tubing of the completion device 412.
[0269] The optimal configuration of the tubings and of the primary
direction of
movement of the completion device 412 in the well bore 410 is dependent upon
many factors including the reservoir 406 properties, the nature of the
enhanced oil
recovery method and the type of primary and secondary mobilising fluids being
into
injected into the reservoir 406.
[0270] In an embodiment the primary mobilising fluid 408 or secondary
mobilising
fluid 450 may contain a nanofluid, i.e. a fluid with nanoadditives which can
aid in
changing the properties of the hydrocarbons to improve recovery. For example,
nanoadditives may be used to reduce the viscosity or modify the surface
tension
properties of reservoir hydrocarbons.
[0271] In an embodiment the primary mobilising fluid 408 or secondary
mobilising
fluid 450 may contain a fluid or solid mobilising catalyst. In an embodiment
the
mobilising catalyst may be a nanoparticle. Nanoparticles may be formed from
any
suitable catalyst.
[0272] In an embodiment the nanoparticles may be made of iron, nickel,
copper,
vanadium, or other metals which have been shown to have a catalytic effect on
upgrading crude oils. For example, Rezai etal., 2013 (Fuel 2013, v113, pp516-
521)
show that nanoparticles are effective in reducing the activation energy of
combustion
reactions.
[0273] In an embodiment the primary mobilising fluid 408 is an oxidant and
the
secondary mobilising fluid 450 is water or steam.
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[0274] In an embodiment, catalysts may be injected with the primary
mobilising
fluid 408, the secondary mobilising fluid 450 or both fluids.
[0275] One advantage of using a primary and secondary mobilising fluid is
that
the presence of the secondary mobilising fluid 450 can reduce the direct
contact of
the primary mobilising fluid 408 with the produced fluids 416 in the well bore
410 by
creating a fluid blanket; thereby reducing unwanted interactions such as
mixing and
reaction.
[0276] Another advantage of using a primary and secondary mobilising fluid
is
that the temperature of the completion device 412, sealing device 440, liner
404 and
well bore 410 can be better controlled. For example, when the primary
mobilising
fluid 408 is an oxidant, the injection of water or steam as the secondary
mobilising
fluid 450 can be used to manage the temperatures inside the well bore 410. By
ensuring temperatures remain within an acceptable range, the mechanical
integrity
of the liner 404, completion device 412 and sealing device 440 may be assured
and
the sealing performance of the sealing devices 440 can be maximised. In this
example, if too high temperatures are measured in the completion device 412
then
the ratio of secondary to primary mobilising fluids can be increased; while if
too low
temperatures are measured in the completion device 412 then the ratio of
secondary
to primary mobilising fluids can be decreased.
[0277] Another advantage of using two mobilising fluids is that one of the
mobilising fluids may be used to inject a catalyst material, in the form of a
fluid and/or
solid, into the reservoir that can catalyse the reaction between the other
mobilising
fluid and the naturally occurring hydrocarbons. For example, catalysts may be
mixed
with the secondary mobilising fluid 450 or may be mixed with the primary
mobilising
fluid 408.
[0278] A major challenge of injecting catalysts into a reservoir using
prior art is
that due to natural reservoir heterogeneity there is little control over where
the
catalysts will end up in the reservoir and whether they will be exposed to the
right
conditions (temperature, pressure, fluid compositions) that will enable them
to be
effective in upgrading the properties of the hydrocarbons. These facts
combined with
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the relatively expensive nature of most catalysts, mean that catalysts are
rarely used
in situ to improve the properties of hydrocarbons before they are produced to
surface.
[0279] An advantage of the present method/system is that it may in some
embodiments address all of the disadvantages of using catalyst in situ in the
prior
art. Firstly, by moving the injection point for the mobilising fluids through
the reservoir
there is much greater control over the rate and flux of the injected
mobilising fluids in
the first place. Secondly, by injecting catalysts with the secondary
mobilising fluid
450, a zone of mobilised hydrocarbons and the catalyst can be created in the
reservoir; which is subsequently contacted with the primary mobilising fluid
408 as
the completion device 412 is moved through the reservoir, thereby creating the
optimal conditions for the catalyst to improve the properties of the
hydrocarbons in
the reservoir.
[0280] In an embodiment, any number of mobilising fluids may be injected
into
the reservoir 406 via the completion device 412.
[0281] Referring to Figure 6, there is generally depicted a hydrocarbon
bearing
subterranean formation 506, a generally horizontal section of a well bore 510
and the
completion device 512 using concentric tubing to enable multi-zone injection
of the
mobilising fluids 508 illustrating certain aspects.
[0282] Mobilising fluids 508 are injected into inner tubing of the
completion
device 512 and exit from apertures 542. The mobilising fluids enter the space
between the completion device 512 and the liner 504 and are injected into the
hydrocarbon reservoir 506. Multiple sets of the apertures 542 may be arranged
along
the length of the well bore 410 so that mobilising fluids 508 may be injected
into
multiple zones of the reservoir 506 at the same time.
[0283] The mobilising fluids 508 form zone(s) of mobilised hydrocarbons
within
the reservoir, in the vicinity of the completion device 512.
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[0284] Produced fluids 516 generated in the zone(s) of mobilised
hydrocarbons
pass through the liner 504 at locations with open area and first enter into
the annulus
between the completion device 512 and the liner 504; and then through
apertures
546 and into annulus 548 between the inner and outer tubings of the completion
device 512.
[0285] In the completion device 512, where required, a conduit (not shown
in
Figure 6) is formed through the device where injection of the mobilising
fluids 508
exit from the device. This conduit is sealed so that mobilising fluids 508 and
produced fluids 516 cannot mix. This conduit connects the annulus 548 formed
between the inner and outer tubings which transports the produced fluids 516
along
the length of the horizontal well bore 510.
[0286] In order to prevent, or at least reduce, the propensity for the
mobilising
fluids 508 to bypass the reservoir 506 and return to surface via the annulus,
one or
more sealing devices 540 are installed to form a seal between the completion
device
512 and the liner 504; and thereby prevent a direct connection from forming
between
the injection apertures 542 and the production annulus. When multi-zone
injection of
mobilising fluids 508 is used, the sealing devices 540 can be arranged so as
to form
multiple zones of mobilised hydrocarbons in the reservoir 506.
[0287] Ideally, the sealing devices 540 would be positioned at locations
such that
they seal with blank sections of the liner 504, as opposed to sections of the
liner 504
containing open area. This is possible, if the liner 504 and completion device
512 are
designed and installed together. However, in general, when the completion
device
512 is used in an old well, with a typical pattern of open area used in
liners, then the
sealing devices 540 will necessarily need to seal against areas of the liner,
containing some open area.
[0288] In an embodiment the configuration of the tubings may be reversed;
so
that mobilising fluids 508 are injected into the outer tubing of the
completion device
512 and exit from apertures 546 and produced fluids 516 enter the inner tubing
of
the completion device through apertures 542 and are produced to surface.
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[0289] Referring to Figure 7, there is generally depicted a hydrocarbon
bearing
subterranean formation 606 with two horizontally drilled well bores 610
illustrating
certain aspects.
[0290] The generally horizontal well bores 610 are drilled through the over
burden formation 618 and into the hydrocarbon bearing reservoir 606 using
standard
directional drilling techniques. Fractures 620 may exist in the reservoir 606
and/or
overburden 618. Casing 622 extends from the surface to the horizontal section
of the
well. Surface casing 628, which may consist of multiple concentric tubings, is
installed into the vertical section of the well. The casings and tubings are
connected
together at surface in a wellhead 30 as is common practice. A liner 604 with a
certain
amount of open area is installed into each horizontal section of the well
bores 610.
[0291] Completion tubing 602 is installed into each well, with two
completion
devices 612, one installed in the middle of the completion tubing 602 and
another
installed at the distal tip of the completion tubing 602.
[0292] The completion tubing may be jointed tubing or it may be coiled
tubing.
The completion tubing 602 may consist of a single tubing or it may consist of
multiple
tubings, including concentric tubings.
[0293] The completion tubing 602 conveys the mobilising fluids 608 from the
surface to the completion devices 612 and conveys the produced fluids 616
extracted from the reservoir 606 from the completion devices 612 to surface.
[0294] Packers 656 may be installed near the heel of the well bore 610 to
isolate
the vertical section of the well bore from the horizontal section of the well
bore.
[0295] Production tubing 624 may be installed into the vertical section of
the well
along with a pump 626.
[0296] Mobilising fluids 608 are injected through the completion tubing 602
and
enter into the completion device 612. The mobilising fluids 608 enter into the
annular
space between the completion device 612 and the liner 604, and are injected
into the
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hydrocarbon bearing reservoir 606 through the open area in the liner 604. In
the
reservoir 606, zones of mobilised hydrocarbons 614 are created, which consists
of
naturally occurring hydrocarbons and the mobilising fluids; and the products
of any
chemical and physical interactions which occur between them. The resulting
mixture
of fluids from the zone of mobilised hydrocarbons 614 flow via gravity,
pressure and
other means back through the liner 604 and may enter the annular space between
the completion tubing 602 and liner 604. From there the produced fluids 616
are
conveyed from the completion devices 612 to the heel of the well bore via the
completion tubing 602. The produced fluids 616 may then be produced to surface
via
a pump 626 and production tubing 624 or via any other artificial or natural
lift
mechanism.
[0297] The zones of mobilised hydrocarbons 614 are located in the vicinity
of the
completion devices 612, from which mobilising fluids 608 and produced fluids
616
are injected to and extracted from the reservoir 606.
[0298] When the hydrocarbons in the zone of mobilised hydrocarbons 614 have
been produced using the completion devices 612, the location of the completion
devices 612 may be moved longitudinally along the horizontal well bore 610, to
enable the mobilisation of hydrocarbons from new portions of the reservoir.
The
completion devices 612 may be moved into or out of the well bore by adding or
removing one or more joints of tubing, when the completion tubing 602 is
jointed; or
by winding or unwinding the coiled tubing if the completion tubing 602 is
coiled.
[0299] In an embodiment, any number of completion devices 612 may be
installed on each completion tubing 602.
[0300] In an embodiment, the horizontal sections of the well bores 610, may
extend from a common well head 630; i.e. the well may be classed as a multi-
lateral
well.
[0301] In an embodiment, any number of predominately single horizontal
wells
610 may be drilled into the reservoir 606 to recover the hydrocarbons present
in the
reservoir.
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[0302] Referring to Figure 8, there is generally depicted a hydrocarbon
bearing
subterranean formation 706. A generally horizontal well bore is drilled into
the
hydrocarbon bearing reservoir 706 using standard directional drilling
techniques. A
liner 704 with a certain amount of open area is installed into the horizontal
section of
the well bore. As shown in Figure 8, the liner 704 may be casing secured in
place by
cement 762 and perforated at locations 760 after installation into the well
bore.
Completion tubing 702 is installed into the well, connecting completion
devices 712
that are installed along the horizontal section of the well bore. Only one
completion
device 712 is labelled, but it should be understood that there are multiple
completion
devices in a row. The completion tubing 702 may consist of a single tubing or
it may
consist of multiple tubings, including concentric tubings. Production tubing
724 may
be installed into the vertical section of the well along with a pump 726.
Mobilising
fluids 708 are injected through the completion tubing 702 and enter into the
completion device 712. Apertures 764 (one aperture shown large for example) in
the
completion device 712 can be opened or closed to enable the mobilising fluids
708
to enter the reservoir 706 at discrete locations via the open area in the well
liner 704.
In the reservoir 706 a zone of mobilised hydrocarbons 714 is created, which
consists
of naturally occurring hydrocarbons and the mobilising fluids; and the
products of any
physical and chemical interactions which occur between them. The resulting
mixture
of fluids from the mobilised zone are labelled as the produced fluids 716. The
produced fluids 716 from the zone of mobilised hydrocarbons 714 flow via
gravity,
pressure and other means back through the liner 704 and may enter the
completion
device 712 through apertures 766, which may also be opened and closed as
desired. The produced fluids are transported to the heel of the well and are
produced
to surface via the pump 726 and production tubing 724.
[0303] As shown in Figure 8, the mobilising fluids 708 can be conveyed
between
adjacent completion devices 712 via completion tubing, and the produced fluids
716
can be conveyed via an annulus 768 formed between the completion devices 712.
[0304] In an embodiment, the mobilising fluids 708 and the produced fluids
716
may be conveyed from the completion devices 712 via separate conduits in the
completion tubing 702.
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[0305] When the hydrocarbons in the zone of mobilised hydrocarbons 714 have
been produced, the apertures 764 for the mobilising fluids 708 and apertures
766 for
the produced fluids 716 may be changed by opening and closing the apertures in
the
completion devices 712 installed along the well bore. By opening and closing
of
apertures 764 and 766 in the completion devices installed along the well bore,
any
desired pattern for the injection of mobilising fluids 708 and production of
produced
fluids 716 may be realised in space and time.
[0306] In an embodiment the apertures 764 and apertures 766 may consist of
a
series of apertures of any desired number, size and open area.
[0307] Figure 9 shows a subsequent injection location for the mobilising
fluids
808 at apertures 864, while produced fluids 816 are recovered from the
reservoir via
apertures 866. As can be seen in Figure 9, the mobilising fluids 808 are being
injected at location that is a distance of three completion devices 812 from
the
injection location in Figure 8. The produced fluids 816 are produced from the
original
location in Figure 8 as well as via completion devices 812 at the three
adjacent
locations. After a portion of the hydrocarbons in the reservoir has been
produced to
surface, a zone of desaturated hydrocarbons 858 is formed in the reservoir
806.
[0308] As is exemplified by Figure 9, the apertures 864 and apertures 866
in
each completion device 812 can be opened or closed in any configuration and in
any
sequence that is desired. Generally, a suitable distance will be maintained
between
the apertures 864 and apertures 866, such that the mobilising fluids 808 do
not
excessively by-pass the reservoir 806.
[0309] As has been exemplified by Figures 8 and 9, the zone of injection
for the
mobilising fluids 808 and the zone of production for the produced fluids 816
along
the wellbore may be changed over time, such that quantity of hydrocarbon
fluids
produced to surface is maximised and such that the hydrocarbons remaining in
the
reservoir 806 is minimised.
[0310] In an embodiment, the zone of injection for the mobilising fluids
808 and
the zone of production for the produced fluids 816 is moved successively along
the
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well bore from the toe to the heel. In an embodiment, the zone of injection
for the
mobilising fluids 808 and the zone of production for the produced fluids 816
is moved
successively along the well bore from the heel to the toe
[0311] In an embodiment the zone of production for the produced fluids 816
is
expanded over time, to maximise the recovery of hydrocarbons from the well
bore.
[0312] Referring to Figure 10, there is generally depicted a side view of a
completion device 912 that incorporates an eccentrically arranged sliding
sleeve.
The completion device 912 is generally contained in a housing 972 and may have
a
sealing material 970 wrapped around the housing 972. An injection sleeve 978
is
arranged eccentrically within the device and is threadedly connected to
completion
tubings 977 and 979. The completion tubings 977 and/or 979 may incorporate
expansion mechanisms (not shown), so that movement of the injection sleeve 978
and thermal and pressure expansion can be accommodated during operations.
[0313] The completion tubing 979 can comprise of a female threaded coupling
981, while completion tubing 977 can comprise of a male threaded coupling 975.
The male and female couplings on either end of the device, enable multiple
completion devices 912 to be connected together during rig up of the
completion
assembly as it is inserted into the well bore.
[0314] Apertures 964 in the housing enable fluids from the inner annulus
982 to
exit the device, while apertures 966 in the housing enable fluids from outside
of the
device to enter into the outer annulus 976. In an embodiment, fluids may enter
or exit
the device via apertures 964 and may enter or exit the device via apertures
966.
[0315] The production sleeve 974 sits concentrically inside the housing
972,
while an injection sleeve 978 is arranged eccentrically within the production
sleeve
974. There exists a sliding sleeve 980 with a shifting profile 984 that can be
engaged
by any suitable shifting tool.
[0316] For example, a common profile for engaging and moving sliding
sleeves is
the OTIS B profile (US Patent 4,436,152 to Fisher et al., 1984). Any suitable
profile
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may be used for the purpose of engaging the sliding sleeve. In an embodiment,
the
sliding sleeve may be moved by any other means known to those skilled in the
art,
including dropping a ball and pressuring up the inner annulus. In an
embodiment the
shifting tool can be deployed on tubing, which is run into the device via
coiled or
jointed tubing from the wellhead.
[0317] In general, it is preferred to use a shifting tool deployed by small
diameter
coiled tubing, where the coiled tubing diameter is between 0.5" and 2", and
more
preferably between 1" and 1 3/4". This method of shifting the sliding sleeve
is
preferred since the location of each sleeve in each completion device 912
within the
well bore can be independently set with only one run in hole operation of the
shifting
tool. This method also avoids placing any material in the inner annulus, such
as
balls, which may obstruct the flow of fluids in the annulus and require other
operations, such as the use of a special fluids to dissolve the ball before
enabling the
full flow of fluids in the annulus 982.
[0318] The sliding sleeve device can comprise of sealing materials and
springs
that are placed around and between parts that move relative to one another in
the
device to seal pathways for fluid flow and hold the position of the parts in
place,
respectively. In an embodiment the sealing materials can be o-rings formed of
any
suitable material.
[0319] In an embodiment, parts may be machined such that channels are
formed
within the device for the flow of fluids to/from the annuli and the outside of
the device
in addition to the direct alignment of the apertures in parts of the device.
[0320] In an embodiment, the sliding sleeve 980, may be positioned within a
recess formed or machined in the injection sleeve 978, so as to minimise the
obstruction of the cross-sectional area for the flow of fluids through the
inner annulus
982.
[0321] When the production sleeve 974 is appropriately aligned in the axial
direction, the produced fluids 916 pass through apertures 966 in the housing
and
apertures 992 in the production sleeve to enter the outer annulus 976.
Similarly,
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when the sliding sleeve 980, the injection sleeve 978 and the production
sleeve 974
are appropriately aligned, the mobilising fluids 908 pass from the inner
annulus 982,
through the apertures 986 in the sliding sleeve 980, apertures 988 in the
injection
sleeve 978, apertures 990 in the production sleeve and apertures 964 in the
housing
972, to exit the completion device 912.
[0322] Referring to Figure 11(a)-(c), there is generally depicted cut-away
views of
an embodiment of a completion device that incorporates an eccentrically
arranged
sliding sleeve device, showing the configurations of the device. Referring to
Figure
11(a), the configuration of the device is such that there can be no flow of
fluids to or
from the device. The production sleeve 1074 is arranged such that the
apertures
1092 in the production sleeve are not aligned with the apertures 1066 in the
housing
1072. The sliding sleeve 1080 is arranged so that the apertures 1086 are not
aligned
with the apertures 1088 in the injection sleeve 1078.
[0323] Referring to Figure 11(b), the configuration of the device is such
that there
can be flow of fluids to or from the inner annulus of the device only. The
sliding
sleeve 1080 is arranged such that the apertures 1086 are aligned with the
apertures
1088 in the injection sleeve 1078, the apertures 1090 in the production sleeve
1074
and the apertures 1064 in the housing 1072. The sliding sleeve 1080 is
arranged so
that the apertures 1092 in the production sleeve 1074 are not aligned with the
apertures 1066 in the housing 1072, thereby preventing flow of fluids to or
from the
outer annulus of the device.
[0324] Referring to Figure 11(c), the configuration of the device is such
that there
can be flow of fluids to or from the outer annulus of the device only. The
sliding
sleeve 1080 is arranged so that the apertures 1092 in the production sleeve
1074
are aligned with the apertures 1066 in the housing 1072, thereby allowing the
flow of
fluids to or from the outer annulus of the device. The sliding sleeve 1080 is
arranged
such that the apertures 1086 are not aligned with the apertures 1088 in the
injection
sleeve 1078, thereby preventing the flow of fluids to or from the inner
annulus of the
device.
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[0325] An advantage of the eccentric design of the completion device is
that the
injection sleeve and production sleeve can be located adjacent to each other,
avoiding a more complex design that is required if the injection sleeve was
located
concentrically within the device. However, a disadvantage of the eccentric
design is
that make-up of the entire completion assembly is more difficult on the
drilling rig
during run in hole operations and adjacent completion devices may need to be
connected together via a completion tubing.
[0326] Another potential disadvantage of the eccentric design is that
during run in
hole operations, the outer diameter of the assembly varies as it passes
through the
well head assembly, making isolation of the reservoir from the surface more
difficult.
The mobilising fluids are transported from the surface to each device via
completion
tubing. The produced fluids will be transported along the well bore via an
annulus
formed by the completion tubing connecting adjacent completion devices and the
well liner.
[0327] Referring to Figure 12, there is generally depicted a view of a
completion
device 1112 that incorporates a concentrically arranged sliding sleeve device.
The
completion device is generally contained in a housing 1172 and may have a
sealing
material 1170 wrapped around it. The sealing material is used to aid
installation and
sealing of the completion device into the well bore liner. Apertures 1164 in
the
housing enable fluids from the inner annulus 1182 to exit the device, while
apertures
1166 in the housing 1172 enable fluids from outside of the device to enter
into the
outer annulus 1176.
[0328] In an embodiment, fluids may enter or exit the device via apertures
1164
and may enter or exit the device via apertures 1166.
[0329] The production sleeve 1174 sits concentrically inside the housing
1172
and is rigidly connected to the injection sleeve 1178 via a solid rib 1196.
Apertures
1192 exist within the production sleeve, while apertures 1188 exist within the
injection sleeve. The solid rib 1196 which connects the injection and
production
sleeves together moves within a slot formed in the wall of the inner tubing
1156. In
an embodiment the number of solid ribs 1196 connecting the injection and
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production sleeves is between one and four, and preferably at least two. There
exists
a shifting profile 1184 on the sliding sleeve 1180 that is connected to
injection sleeve
1178 and which can be engaged by any suitable shifting tool that is run inside
the
inner annulus 1182 of the device. Stoppers 1158 are located on the housing to
limit
the travel of the production sleeve 1174.
[0330] A hollow rib 1194 connects the inner tubing 1156 with the housing
1172
and has holes 1190 which can provide a pathway from the inner annulus 1182 to
the
outside of the device. In an embodiment the number of hollow ribs 1194
connecting
the inner tubing 1156 and the housing 1172 is between one and four, and
preferably
at least two. The solid ribs 1196 and hollow ribs 1194 are orientated in the
azimuthal
direction so as to not interfere with each other whatever the position of the
sliding
sleeve 1180. The production sleeve 1174 has slots for the hollow ribs 1194, so
that it
can move relative to the housing 1172, the hollow ribs 1194 and the inner
tubing
1156 which are all connected rigidly together.
[0331] When the sliding sleeve 1180 is positioned as shown in Figure 12 (to
the
far right), the apertures 1188 in the injection sleeve 1178 do not align with
the holes
1190 in the hollow rib 1194 and no flow is possible between the inner annulus
and
the outside of the device. Similarly, the apertures 1192 in the production
sleeve 1174
do not align with the apertures 1166 in the housing and no flow is possible
between
the outer annulus 1176 and the outside of the completion device. This position
of the
sliding sleeve is used when installing the completion device into the well
bore and
when it is desired that there be no flow between the outside of the device and
any of
the annuli inside the device.
[0332] In an embodiment, parts of the completion device 1112, which are
shown
as one part, may be manufactured as two or more parts and joined together
during
assembly of the device. For example, the housing 1172, may consist of one, two
or
three machined tubings which are joined together. For example, the inner
tubing
1156 may consist of more than one tubing joined together.
[0333] In an embodiment, the diameter of the housing 1172 of the completion
device and the thickness of the sealing material 1170 shall be chosen to
enable a
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snug installation into the well liner and/or well bore. Generally well liners
are
manufactured in common sizes, with these being between about 2" and 12"
outside
diameter (OD), and more commonly between about 4" and 7" OD.
[0334] In an embodiment, the inner diameter (ID) of the inner sleeve 1178
and
the design of sliding sleeve 1180, will be designed such that tools having an
OD of
between about 0.5" and 3.5" OD can be run through the completion device 1112.
More generally, the design of the device will enable shifting tools deployed
on coiled
tubing to be run into and through the device to move the sliding sleeve. The
most
common sizes of coiled tubing are between 1" and 3.5" OD, with coiled tubing
of 1",
1.5", 1 3/4" and 2" OD being preferred for use with the completion device
1112.
[0335] Referring to Figure 13, there is generally depicted a view of a
completion
device 1212 that incorporates a concentrically arranged sliding sleeve device.
In
Figure 13, the sliding sleeve 1280 has been positioned such that the apertures
1288
in the injection sleeve 1278 are aligned with the holes 1290 of the hollow rib
1294,
thereby allowing flow of the mobilising fluids 1208 from the inner annulus
1282 of the
completion device 1212 to the outside through the apertures 1264. In an
embodiment, the flow may occur from the outside of the device, through
apertures
1264 and holes 1290 into the inner annulus 1282 of the device. When the
sliding
sleeve is positioned as shown in Figure 13, the apertures 1292 in the
production
sleeve 1274 do not align with the apertures 1266 in the housing 1272 and no
flow is
possible between the outer annulus 1276 and the outside of the completion
device
1212.
[0336] Referring to Figure 14, there is generally depicted a view of a
completion
device that incorporates a concentrically arranged sliding sleeve device. In
Figure
14, the sliding sleeve 1380 has been positioned such that the apertures 1392
in the
production sleeve 1374 are aligned with the apertures 1366 in the housing
1372,
thereby allowing flow of produced fluids 1316 from outside of the device and
into the
outer annulus 1376. In an embodiment, the flow may occur from outer annulus
through apertures 1392 and 1366 to the outside of the device. When the sliding
sleeve 1380 is positioned as shown in Figure 14, the apertures 1388 in the
injection
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sleeve 1378 do not align with the holes 1390 in the hollow rib 1394 and
apertures
1364 in the housing and no flow is possible between the inner annulus 1382 and
the
outside of the completion device 1312.
[0337] In an embodiment, the injection sleeve 1378 can be modified, such
that
the apertures 1388 align with the holes 1390 in the hollow rib 1394 when the
apertures 1392 in the production sleeve 1374 align with the apertures 1366 in
the
housing, thereby enabling flow to or from both the inner and outer annuli and
the
outside of the completion device 1312.
[0338] In an embodiment, the completion device 1312 will be in the range of
from
about 1 to about 10 meters long. In an embodiment, the completion device will
have
a length equal to commonly available jointed tubulars.
[0339] The aforementioned eccentric and concentric completion devices both
enable the independent flow of two fluids to or from the reservoir as however
desired
during operations. Since, it is envisaged that multiple completion devices
will be
installed into a single well bore, the completion devices enable a large
number of
combination and sequences of injection and production to/from the annuli. For
example, during operations all completion devices may be set to be
"producers",
whereby fluids enter the device through the housing and are transported via
the
outer annulus to the heel of the wellbore. For example, all completion devices
may
be set to "injectors", whereby fluids are transported from the surface via the
inner
annulus and are injected into the reservoir. For example, some completion
devices
may be set to be "injectors" and some may be set to be "producers" and the set
of
"injectors" and "producers" may be changed over time.
[0340] Referring to Figure 15, there is generally depicted a hydrocarbon
bearing
subterranean formation 1406. A generally horizontal well bore is drilled into
the
hydrocarbon bearing reservoir 1406 using standard directional drilling
techniques. A
liner 1404 with a certain amount of open area is installed into the horizontal
section
of the well bore. The liner may be installed into the open bore hole or it may
be
secured in place with a gravel pack 1462 (as shown). Completion tubing 1402 is
installed into the well, connecting completion devices 1412 that are installed
along
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the horizontal section of the well bore. The completion tubing 1402 may
consist of a
single tubing or it may consist of multiple tubings, including concentric
tubings. As
shown in Figure 15, the completion devices 1412 are concentric completion
devices
like those described in Figures 12 through 14. The completion devices 1412 may
be
connected together directly or may be connected via concentric tubing, which
may
comprise of expansion joints. Production tubing 1424 may be installed into the
vertical section of the well along with a pump 1426.
[0341] Mobilising fluids 1408 are injected through the completion tubing
1402
and enter into the completion device 1412. The location of the sliding sleeve
in each
device determines which apertures are opened and closed. Apertures 1464 in the
completion device 1412 can be opened or closed to enable the mobilising fluids
1408 to enter the reservoir 1406 at discrete locations via the open area in
the well
liner 1404. In the reservoir 1406 a zone of mobilised hydrocarbons 1414 is
created,
which consists of naturally occurring hydrocarbons and the mobilising fluids;
and the
products of any physical and chemical interactions which occur between them.
The
resulting mixture of fluids from the mobilised zone are labelled as the
produced fluids
1416. The produced fluids 1416 from the zone of mobilised hydrocarbons 1414
flow
via gravity, pressure and other means back through the liner 1404 and may
enter the
completion device 1412 through apertures 1466, which may also be opened and
closed as desired. The produced fluids are transported to the heel of the well
and are
produced to surface via the pump 1426 and production tubing 1424.
[0342] As shown by the arrows in Figure 15, some of the completion devices
1412 can be set to be "injectors" (arrow shown pointing out of the device) and
some
of the completion devices 1412 can be set to be "producers" (allow shown
flowing
into the device) in such an arrangement so that the zone of mobilised
hydrocarbons
1414 spans the entire length of the horizontal well bore.
[0343] In an embodiment a Cyclic Injection steam assisted gravity drainage
(CI-
SAGD) process can be established using a single well. Steam is used as the
mobilising fluid 1408 and the reservoir 1406 consists of immobile viscous
"heavy" oil
at reservoir conditions, such as heavy oil or oil sands bitumen. The zone of
mobilised
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hydrocarbons forms a steam chamber, wherein the steam injected migrates to the
top of the reservoir and then condenses. The condensing steam mixes with the
heavy oil in the reservoir, forming the produced fluids 1416 which drain back
into the
completion devices 1412 with the apertures 1466 in the open position and are
produced to surface via the production tubing 1424. In order to prevent direct
by-
passing of the injected steam 1408 to the production annulus of the completion
device 1412, an appropriate distance is maintained between adjacent
"injectors" and
"producers". As shown in Figure 15, every second completion device 1412 can be
set to be "closed" such that there is no flow to or from either annuli of the
device. In
an embodiment, the apertures 1464 and apertures 1466 in each device can be
positioned a suitable distance from the end of the device, such that when the
devices
are connected together an appropriate distance is maintained between the
adjacent
injection and production apertures.
[0344] In an embodiment, in order to maximise the recovery of hydrocarbons
from the reservoir 1406, the completion devices 1412 which are designated as
"injectors" and "producers" can be changed over time and the sequence may be
repeated in time, hence the designation as a cyclic injection SAGD process (CI-
SAGD).
[0345] An advantage of the present method/system over previous single well
SAGD concepts reported in the literature, is that a pseudo-steady steam
chamber
can be generated by moving the injection and production zones in a pattern
along
the wellbore and then cycling this pattern over time. The prior art is limited
by having
fixed locations for the injection of the mobilising fluids and the production
of the
produced fluids, and thereby the steam chamber which develops in designs of
the
prior art are inherently skewed, as the injection and production zones are
laterally
offset from one another. In the static injection concepts disclosed in the
prior art, the
oil mobilised in the vicinity of the "injector" needs to travel to the
"producer" to be
produced to surface, which may be several tens of metres away. This reduces
the oil
recovery factor and reduces efficiency of the process. By moving the injection
and
production zones, a pseudo-steady steam chamber more similar to that developed
in
a conventional SAGD process with the injector located above the producer can
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established. In addition, oil mobilised by the injection of steam at one time
(operation
as "injector"), can be produced by at a later time from the same zone
(operation as
"producer") by only travelling a few metres.
[0346] In an embodiment, the mobilising fluid of the CI-SAGD process can be
any combination of desired mobilising fluids known in the art, including
steam,
solvents and non-condensable gases.
[0347] In an embodiment, when the completion devices 1412 are used for a
thermal oil recovery process like the CI-SAGD process shown in Figure 15, the
completion devices may be modified to thermally isolate the inner annulus from
the
outer annulus. Thermal isolation of the inner and outer annuli improves the
thermal
efficiency of the process, as the injected steam will reach the reservoir at a
higher
temperature and/or higher quality than it would without thermal isolation. The
thermal
isolation may be achieved by using suitable insulation materials and/or using
vacuum insulated tubing as is well known in the art.
[0348] Referring to Figure 16, there is generally depicted two combinations
and
sequences of "injectors" and "producers", the patterns of which may be
repeated
along the length of the horizontal well bore. Figure 16(a), shows a pattern
with two
completion devices 1512, with one designated as "injector" 1565 and the second
one
designated as "producer" 1567. If the apertures in the "injector" are a
sufficient
distance from the apertures in the "producer" the problem of by-passing of the
mobilising fluids is avoided. In the stage 1 sequence, one of the completion
devices
is designated as the "injector" and the other completion device is designated
as the
"producer". After a set time, the "injector" and "producer" are swapped to
form the
combination shown in stage 2. After a set time, the "injector" and "producer"
may be
swapped again to form the combination in stage 1. The pattern may be repeated
as
required to maximise the recovery of hydrocarbons from the formation. Figure
16(b)
shows a pattern with four completion devices 1512, in which one is designated
an
"injector" 1565, one a "producer" 1567 and the remaining two are "closed". In
this
pattern there exists a "closed" completion device between adjacent "injectors"
and
"producers". The completion device designated as the "injector" and the
completion
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device designated as the "producer" is changed at each stage as shown in
Figure
16(b). A total of four stages is required before the pattern of injectors and
producers
is repeated. The pattern of completion devices shown in Figure 15 is the same
as
stage 1 of Figure 16(b), i.e. it is the first stage of the pattern shown in
Figure 16(b).
[0349] In an embodiment the set of completion devices in a well bore may be
arranged to form any desired combination of "injectors" and "producers", and
further
the arrangement may be changed to form any other desired combination in any
sequence in time. A major advantage of the present method/system is the
flexibility
provided by the completion devices to form arrangements of "injectors" and
"producers" along the well bore.
WELL PAIR
[0350] Referring to Figure 17, there is generally depicted a hydrocarbon
bearing
subterranean formation 1606 with two horizontally drilled well bores 1610
illustrating
certain embodiments. Casing 1622 extends from the surface to the horizontal
section
of the well. Surface casing 1628, which may consist of multiple concentric
tubings, is
installed into the vertical section of the well. A liner 1604 with a certain
amount of
open area is installed into each horizontal section of the well bores 1610.
[0351] The first well can be called the injection well 1668. The second
well can
be called the production well 1670.
[0352] Injection tubing 1658 in the form of a completion assembly is
installed into
the injection well 1668, with two injection devices 1660 (completion devices),
one
installed in the middle of the injection tubing 1658 and another installed at
the distal
tip of the injection tubing 1658. The injection tubing 1658 may be jointed
tubing or it
may be coiled tubing. The injection tubing 1658 may consist of a single tubing
or it
may consist of multiple tubings, including concentric tubings. The injection
tubing
1658 conveys the mobilising fluids 1608 from the surface to the injection
devices
1660.
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[0353] Mobilising fluid(s) 1608 are injected through the injection tubing
1658 and
enter into the injection device 1660. The mobilising fluids 1608 enter into
the annular
space between the injection device 1660 and the liner 1604, and are injected
into the
hydrocarbon bearing reservoir 1606 through the open area in the liner 1604.
[0354] Packers 1656 may be used in the injection and/or production wells to
isolate the horizontal section from the vertical section of the wells.
[0355] In an embodiment the mobilising fluids 1608 may include a primary
mobilising fluid and a secondary mobilising fluid that are injected into
different
regions of the reservoir 1606 using the injection device 1660 and injection
tubing
1658.
[0356] In the reservoir 1606, one or more zones of mobilised hydrocarbons
1614
are created, each of which consists of naturally occurring hydrocarbons and
the
mobilising fluids; and the products of any chemical and physical interactions
which
occur between them. The zone of mobilised hydrocarbons 1614 may form one or
more relatively permeable connections between the injection well 1668 and the
production well 1670.
[0357] The mixture of fluids 1662 from the zones of mobilised hydrocarbons
1614
flow via gravity, pressure and other means through the liner 1604 in the
production
well 1670 and may enter the annular space between the production device 1664
and
liner 1604. From there the produced fluids 1616 are conveyed from the
production
device 1664 to the surface via the production tubing 1666.
[0358] In an embodiment the produced fluids may be produced to the heel of
the
well bore via the production tubing 1666. The produced fluids 1616 may then be
produced to surface via a pump and production tubing or via an artificial lift
mechanism.
[0359] To recover all of the hydrocarbons in the vicinity of the injection
and
production wells, the injection devices 1660 and production devices 1664 may
be
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moved longitudinally along the horizontal well bores 1610 and 1670, to enable
the
mobilisation of hydrocarbons from new portions of the reservoir
[0360] The injection devices 1660 and production devices 1664 may be moved
into or out of the well bores by adding or removing one or more joints of
tubing, when
the tubing is jointed; or by winding or unwinding the coiled tubing when the
tubing is
coiled.
[0361] Generally, the injection devices 1660 and production devices 1664
will be
moved in unison into or out of the well bores; so that the zones of mobilised
hydrocarbons formed between them will be "swept" in unison through the
reservoir.
[0362] To recover all of the hydrocarbons in the vicinity of the injection
and
production wells the injection and production devices may be swept along the
full
length of the horizontal section of each well bore.
[0363] In an embodiment, the injection devices 1660 and production devices
1664 may be fixed in place and apertures in the devices may be opened and
closed
in sequence, by manipulating sliding sleeve devices within them, in order that
the
zones of mobilised hydrocarbons formed between the two wells will be swept
through the reservoir.
[0364] In an embodiment, the injection tubing 1658 may be installed in the
well
bore 1610 from the beginning of the injection of mobilising fluids 1608 into
the
reservoir 1606.
[0365] It is generally recognized that the hydrocarbon recovery factor is
maximized by using injection and production wells during enhanced oil recovery
operations; however, in some cases, overlapping zones of mobilised
hydrocarbons
are required to be established before injection from one well and production
from
another can occur. For example, in heavy oil recovery using SAGD a zone of
mobile
hydrocarbons should be present between the upper injection and lower
production
well before steam injection into the reservoir is attempted
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[0366] In an embodiment the horizontal wells may be arranged in any
pattern.
For example, the injection well 1658 may be placed at a higher or lower
elevation in
the reservoir 1606 than the production well 1670.
[0367] In an embodiment, the production well 1670 may be placed down-dip of
the injection well 1668 in the reservoir 1606.
[0368] Referring to Figure 18, there is generally depicted a hydrocarbon
bearing
subterranean formation 1706 with two horizontally drilled well bores 1710
illustrating
certain embodiments.
[0369] The generally horizontal well bores 1710 are drilled through the
over
burden formation 1718 and into the hydrocarbon bearing reservoir 1706 using
standard directional drilling techniques. Casing 1722 extends from the surface
to the
horizontal section of the well. Surface casing 1728, which may consist of
multiple
concentric tubings, is installed into the vertical section of the well. A
liner 1704 with a
certain amount of open area is installed into each horizontal section of the
well bores
1710.
[0370] One of the wells is called the injection well 1768. The other well
is called
the production well 1770.
[0371] Injection tubing 1758 is installed into the injection well 1768,
with two
injection devices 1760, one installed in the middle of the injection tubing
1758 and
another installed at the distal tip of the injection tubing 1775.
[0372] The injection tubing 1758 may be jointed tubing or it may be coiled
tubing.
The injection tubing 1758 may consist of a single tubing or it may consist of
multiple
tubings, including concentric tubings.
[0373] The injection tubing 1758 conveys the mobilising fluids 1708 from
the
surface to the injection devices 1760.
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[0374] Mobilising fluids 1708 are injected through the injection tubing
1758 and
enter into the injection device 1760. The mobilising fluids 1708 enter into
the annular
space between the injection device 1712 and the liner 1704, and are injected
into the
hydrocarbon bearing reservoir 1706 through the open area in the liner 1704.
[0375] In an embodiment the mobilising fluids 1708 may include a primary
mobilising fluid and a secondary mobilising fluid that are injected into
different
regions of the reservoir 806 using the injection device 1760 and injection
tubing
1758.
[0376] In the reservoir 1706, one or more zones of mobilised hydrocarbons
1714
are created, each of which consists of naturally occurring hydrocarbons and
the
mobilising fluids; and the products of any chemical and physical interactions
which
occur between them. The zone of mobilised hydrocarbons 1714 may form one or
more relatively permeable connections between the injection well 1768 and the
production well 1770.
[0377] The mixture of fluids 1762 from the zones of mobilised hydrocarbons
1714
flow via gravity, pressure and other means through the liner 1704 in the
production
well 1770. From there the produced fluids 1716 are produced to surface via
production tubing 1724 and a pump.
[0378] To recover all of the hydrocarbons in the vicinity of the injection
and
production wells, the injection devices 1760 may be moved longitudinally along
the
horizontal well bore 1710, to enable the mobilisation of hydrocarbons from new
portions of the reservoir.
[0379] The injection devices 1760 may be moved into or out of the well
bores by
adding or removing one or more joints of tubing, when the tubing is jointed;
or by
winding or unwinding the coiled tubing when the tubing is coiled.
[0380] To recover all of the hydrocarbons in the vicinity of the injection
and
production wells the injection devices may be swept along the full length of
the
horizontal section of each well bore.
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[0381] In an embodiment, the injection devices 1760 may be fixed in place,
and
apertures in the devices may be opened and closed in sequence, by manipulating
sliding sleeve devices within them, in order that the zones of mobilised
hydrocarbons
formed between the two wells will be swept through the reservoir.
[0382] In an embodiment, the injection tubing 1758 may be installed in the
well
bore 1710 from the beginning of the injection of mobilising fluids 1708 into
the
reservoir 1706
[0383] In an embodiment, an oblique front of mobilised fluids may be formed
between the injection well and the production well, due to the movement of the
injection zone in the injection well. By oblique it is meant that the gradient
of the
mobilised fluid is offset from a perpendicular angle with respect to the well
bore. The
oblique nature of the front is shown schematically in the Figures. It should
be
understood that if a trend line were drawn through the front, the trend line
would be
at an oblique angle with respect to the well bore. In embodiment, the oblique
angle
can be in the range of from 95 to 150 degrees, such as at least about 110,
120, 130
or 140 degrees. The obliqueness of the angle can be changed by changing the
rate
and the location of the injection relative to the rate and location of
production.
[0384] There are several advantages of generating an oblique front between
the
injection and production wells. Firstly, an obliquely orientated front of
mobilised
hydrocarbons is larger than a front substantially perpendicular to the wells.
Thus, the
injectivity of the mobilising fluids may be greater when an oblique front has
developed between the wells due to the movement of the injection zone.
[0385] Secondly, the by-passing of the mobilising fluids through the
reservoir is
influenced by the orientation of the front of mobilised fluids in relation to
fractures or
permeable pathways within the reservoir.
[0386] It is often difficult to establish a front of mobilising fluids
perpendicular to a
fracture or other high permeability zone, because the mobilising fluids will
naturally
want to flow through the fracture in preference to flowing through the matrix
of the
reservoir.
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[0387] Therefore, if there are any zones of high permeability between the
injection and production wells, it can be difficult to establish a continuous
front of
mobilising fluids between the wells and recover a majority of the hydrocarbons
in the
reservoir. In severe cases, the mobilising fluid will tend to flow through the
high
permeability pathways and by-pass large regions of the reservoir resulting in
poor
recovery of the hydrocarbons and/or poor utilisation of the mobilising fluid
[0388] As is shown in several of the examples provided in this
specification, by
moving the injection zone along the axis of the horizontal section of the
injection well,
the recovery of hydrocarbons can be improved if fractures are present in the
reservoir.
[0389] In an embodiment the horizontal wells may be arranged in any pattern
in
the formation.
[0390] Referring to Figure 19, which shows an embodiment for the injection
device 1860 using a concentric tubing string arrangement, which enables the
injection of a primary mobilising fluid 1808 and a secondary mobilising fluid
1850.
[0391] A generally horizontal well bore 1810 is drilled into the
hydrocarbon
bearing reservoir 1806 using standard directional drilling techniques. A liner
1804
with a certain amount of open area is installed into the well bore 1810. The
injection
device 1860 uses a concentric tubing arrangement.
[0392] Primary mobilising fluids 1808 are injected through the inner tubing
of the
concentric tubing of the injection device 1860. The primary mobilising fluids
1808 exit
from apertures 1842 into the annulus between the injection device 1860 and the
liner
1804. The primary mobilising fluids 1808 are injected into the hydrocarbon
bearing
reservoir 1806 through the open area in the liner 1804.
[0393] The liner may have any arrangement of open area, including slots,
holes,
or permeable meshes, such as wire wraps, installed in any manner. In many
applications, liners 1804, have slots 1844 manufactured into them.
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[0394] Secondary mobilising fluids 1850 are injected through the annulus
1848
formed between the outer and inner tubings and exit from apertures 1846 into
the
annulus between the injection device 1860 and the liner 1804. The secondary
mobilising fluids 1850 are injected into the hydrocarbon bearing reservoir
1806
through the open area in the liner 1804.
[0395] In the reservoir 1806 a zone of mobilised hydrocarbons is created,
which
consists of naturally occurring hydrocarbons and the primary and secondary
mobilising fluids; and the products of any chemical and physical interactions
which
occur between them.
[0396] In order to ensure that the primary mobilising fluids 1808 and
secondary
mobilising fluids 1850 are injected into the appropriate regions of the
reservoir 1806,
sealing devices 1840 are installed to form a seal between the injection device
1860
and the liner 1804 and to isolate the injection regions of the primary
mobilising fluid
1808 and the secondary mobilising fluids 1850.
[0397] In an embodiment the configuration of the tubings may be reversed;
so
that primary mobilising fluids 1808 are injected into annulus 1848 formed
between
the inner and outer tubing of the injection device 1860 and the secondary
mobilising
fluids 1850 are injected into the inner tubing of the injection device 960.
[0398] The operation of the injection device 1860, enables the formation of
a
zone of mobilised hydrocarbons from the injection of the secondary
mobilisation fluid
1850, which is subsequently contacted with the primary mobilising fluid 1808,
when
the injection device 1860 is moved out of the well bore 1810; or which enables
the
formation of a zone of mobilised hydrocarbons from the injection of the
primary
mobilising fluid 1808, which is subsequently contacted with the secondary
mobilising
fluid 1850, when the injection device 1860 is moved into the well bore 1810.
[0399] In an embodiment the injection device 1860 is moved such that
adjacent
zones of mobilised hydrocarbons overlap.
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[0400] In an embodiment the injection device 1860 is moved a distance equal
to
the distance between adjacent sealing devices 1840. In an embodiment the
injection
device 1860 is moved a distance equal to the distance between the apertures
1842
and the apertures 1846.
[0401] In an embodiment the primary mobilising fluid 1808 or secondary
mobilising fluid 1850 may contain a fluid or solid mobilising catalyst. In an
embodiment the mobilising catalyst may be a nanoparticle.
[0402] In an embodiment the primary mobilising fluid 1808 is an oxidant and
the
secondary mobilising fluid 1850 is water or steam.
[0403] In an embodiment, catalysts may be injected with the primary
mobilising
fluid 1808, the secondary mobilising fluid 1850 or both fluids.
[0404] An advantage of using two mobilising fluids is that one of the
mobilising
fluids may be used to inject a catalyst material, in the form of a fluid
and/or solid, into
the reservoir that can catalyse the reaction between the other mobilising
fluid and the
naturally occurring hydrocarbons. For example, catalysts may be mixed with the
secondary mobilising fluid 1850 or may be mixed with the primary mobilising
fluid
1808.
[0405] An advantage of some embodiments is that by moving the injection
point
for the mobilising fluids through the reservoir there can be much greater
control over
the rate and flux of the injected mobilising fluids in the first place.
Secondly, by
injecting catalysts with the secondary mobilising fluid 1850, a zone of
mobilised
hydrocarbons and the catalyst can be created in the reservoir; which is
subsequently
contacted with the primary mobilising fluid 1808 as the injection device 1860
is
moved through the reservoir, thereby creating the optimal conditions for the
catalyst
to improve the properties of the hydrocarbons in the reservoir.
[0406] In an embodiment, any number of mobilising fluids may be injected
into
the reservoir 1806 via the injection device 1860.
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EXAMPLES
[0407] Examples of embodiments of the invention and other embodiments are
now described which are exemplary only and non-limiting.
Example 1: Single point Moving Injection Combustion Stimulation (MICS)
[0408] This example was prepared using computer simulations of the recovery
process using the STARSTm Thermal Simulator general issue 2018, provided by
Computer Modelling Group of Calgary, Alberta, Canada.
[0409] The simulations were made with a set of simplified components, and
reactions to represent the key features of the combustion of heavy oil. In the
simulations the heavy oil is modelled as being composed of the pseudo-
components:
maltenes and asphaltenes. The reaction scheme and stoichiometric parameters
are
provided in Table 1 and are derived from the work of Be!grave et al. (J. D. M.
Be!grave, R. G. Moore, M. G. Ursenbach and D. W. Bennion, "Comprehensive
Approach to In-Situ Combustion Modeling", Society of Petroleum Engineers, SPE
Paper 20250, 1993). Table 2 provides the kinetic parameters for each reaction
assuming a first order reaction rate, r = A exp( -E / RT ) C, where A is the
pre-
exponential factor (variable units), E is the activation energy (J/mol), R is
the gas
constant (= 8.314 x 103 J/mol-K) and T is the temperature (K) and C is the
concentration of the reactant. Table 3 provides parameters for the reservoir.
Table 1
Reaction Scheme and Stoichiometry for Heavy Oil Combustion
Reaction Reaction Stoichiometry
Description
1 Thermal cracking Maltenes 4 0.372 Asphaltenes
2 Thermal cracking Asphaltenes 4 83.206 Coke
3 Low Temperature Maltenes + 3.431 02 4 0.4737 Asphaltenes
Oxidation
4 Low Temperature Asphaltenes + 7.513 02 4 101.559 Coke
Oxidation
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High Temperature Coke + 1.230 02 4 0.8968 CO2 + 0.1 N2 CO +
Oxidation 0.565 H20
Table 2
Reaction Kinetics for Heavy Oil Combustion
Reaction Pre-Exponential Units
Activation Heat of Reaction
Factor A Energy E (J/mol)
(J/mol)
1 4.05 x 101 day-1 1.16x 106 0
2 1.82 x 104 day-1 4.02 x 104 0
3 2.12 x 105 day-i kpa-o 4246
4.61 x 104 1.30 x 106
4 1.09 x 105 day-1kPa-4 7627
3.31 x 104 2.86 x 106
5 3.88 x 100 day-1kPa-1
8.21 x 102 4.95 x 105
Table 3
Reservoir Parameters
Parameter Units
Value
Porosity % 32
Permeability lateral (X, Y) mD 4000
Permeability vertical (Z), assumed 75% of lateral permeability mD 3000
Reservoir Temperature C 29
Reservoir Pressure kPag 3750
Oil gravity @ 15.6 C API 10.5
Oil density kg/m3
996.5
Oil viscosity at 20 C cP
62,743
Oil saturation % 80
Water saturation % 20
Assumed auto-ignition temperature C >180
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[0410] The rate of heavy oil production and cumulative oil recovery using a
method for recovering petroleum from a hydrocarbon-bearing subterranean
formation in accordance with an embodiment has been modelled in computer
simulations. Model parameters are shown in Table 4, below.
Table 4
Computer simulation parameters
Parameter Units
Value
Top of oil reservoir m 760
Bottom of oil reservoir m 775
Oil reservoir thickness m 15
Top of oil reservoir pressure KPag
3,750
Bottom of oil reservoir pressure KPag
4,043
Injection/production well, height above bottom of reservoir m 3.75
Pay thickness of reservoir above Injection/Production well m
11.25
Injection/Production well horizontal length m 92
Oxidant - Air
Oxidant injection rate Sm3/day
6,000
Oxidant injection temperature C 25
Injection zone length m 4
Injection zone rate of movement m/day
0.0667
Initial oxidant injection pressure KPag
6,000
Production zone distance from end of injection zone m 24
[0411] The simulation is of the Moving Injection Combustion Stimulation
(MICS)
process which uses a single horizontal well bore and a single point injection
of
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oxidant into the reservoir and a single production zone, in a configuration
similar to
Figure 9. The computational domain is 100 m (axially) x 15 m (vertically) x 25
m
(laterally). The computational domain is symmetric and represents one-half of
the
actual domain penetrated by the well. The reported data is for the full
domain, i.e. for
lateral extent of 50 m, 25 m on either side of the well's centreline.
[0412] The horizontal well is located 3.75 m from the bottom of the
reservoir,
which is 15 m thick thereby providing 11.25 m of net pay. The reservoir is of
heavy
oil with an initial oil saturation of 80% and an initial water saturation of
20%. The
thermophysical parameters of the heavy oil are typical of reservoirs that may
are
found in Alberta and Saskatchewan in Canada.
[0413] The oxidant is initially injected at a location 62 m from the heel
of the well
bore, from a zone of 4 m in length. The production zone is initially located
at a
location 88 m from the heel of the well and runs until the end of the well
bore which
has a total length of 92 m. The oxidant, air, is injected at an average rate
of 6,000
5m3/day. After a short initial ramp up phase, the start of the injection and
production
zones are retracted at a rate of 4 m every 60 days, or at an average rate of
0.0667
m/day. The length of the production zone is increased as the injection zone
moves
closer towards the heel of the well bore, so that heated oil can drain into
the
production annulus and be produced to surface. A fixed distance of 24 m exists
between the injection zone and the production zone throughout the simulation.
[0414] Figure 20(a) shows the injection and production configuration in the
well
bore 1910 and the temperature profile cross-section in the reservoir 1906 on
day 396
of the simulation. At this time, the oxidant 1908 is injected into the
reservoir at a
position 54 m from the heel of the well bore, and the produced fluids 1916 are
recovered from a zone near the toe of the well bore. The reaction of the
oxidant 1908
with the hydrocarbons in the reservoir 1906, generates a combustion zone 1921
located above the well bore with a temperature of over 400 C, A zone 1922
exists
around the combustion zone where the temperature is between 300 and 400 C.
Similarly a lower temperature zone 1923 exists where temperatures are between
200 and 300 C. An evaporation zone 1924 exists around the combustion process
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where temperatures vary between 100 and 200 C and where water originally
present in the reservoir 1906 can be turned to steam. The reservoir 1906 has a
temperature below 100 C and generally close to the initial temperature of 29
C..
[0415] Figure 20(b) shows the well configuration and temperature contours
in the
reservoir at day 762 of the simulation. At this time the oxidant 1908 is
injected at a
position 32 m from the heel of the well and the production zone extends for 30
m
from the toe of the well bore 1910. It can be seen that the combustion zone
1921
remains located close to and above where the oxidant 1908 is injected into the
reservoir, while the other zones 1922, 1923 and 1924 have expanded in size.
[0416] Figure 20(c) shows the well configuration and temperature contours
in the
reservoir at day 1157 of the simulation, when the injection zone is close to
the heel
of the well bore. The combustion zone 1921 remains close to and above the
region
of oxidant injection, while the temperature along the well bore where produced
fluids
1916 are collected varies from about 300 to 100 C, ensuring a low viscosity
of the
heavy oil in the region of the production zone.
[0417] The original oil in place for the domain is 19,200 m3. The produced
oil rate
averages 4.22 m3/day with a maximum of 35.64 m3/day. Over the period of 1765
days, the cumulative oil production to surface is 6,262 m3 yielding an oil
recovery
factor of 32.6%. A further 1,180 m3 of oil is consumed in the process
representing
6.1% of the original oil in place. Table 5 shows a summary of the simulation
results.
[0418] The average AOR of the MICS process is estimated to be about 1400
m3/m3 which is within the economically feasible range (G. Perkins,
"Mathematical
modelling of in situ combustion and gasification", Proc. IMechE, Part A:
Journal of
Power and Energy, v323, n1, pp56-73, 2017). Also, the simulations show no or
limited breakthrough of oxygen to the production zone during the moving
injection
process. In the simulations the horizontal well has been placed 3.75 m from
the
bottom of the reservoir. If the well was instead located at 1 m from the
bottom, it is
estimated that the oil recovery factor would increase to over 40 %.
Table 5
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Computer simulation results
Parameter Units
Value
Original oil in place m3
19,200
Total simulation time days
1,765
Air injection rate Sm3/day
6,000
Average oil production rate m3/day
4.22
Average air oil ratio m3/m3
1,423
Oil produced to surface m3
6,262
Oil recovery factor % 32.6
Example 2: Two point Moving Injection Combustion Stimulation (MICS)
[0419] This example was prepared using computer simulations of the recovery
process using the STARSTm Thermal Simulator general issue 2018, provided by
Computer Modelling Group of Calgary, Alberta, Canada.
[0420] The simulations were made with the same set of components, reactions
and reservoir properties as used in Example 1. The simulation is of the two
point
Moving Injection Combustion Stimulation (MICS) process which uses a single
horizontal well bore with two injection zones for the oxidant and two
production
zones for the produced fluids. The computational domain is 200 m (axially) x
15 m
(vertically) x 25 m (laterally). The simulation domain is symmetric and one-
half of
what an actual well would encounter, while the reported data is for the full
well
model. The horizontal well is located 3.75 m from the bottom of the reservoir,
which
is 15 m thick thereby providing 11.25 m of net pay.
[0421] The oxidant is initially injected at two locations, one 62 m and
another at
162 m from the heel of the well, with each zone being 4 m in length. The two
production zones are initially located at 88 m and 188 m from the heel of the
well and
are initially 4 m in length also. The oxidant, air, is injected at a maximum
rate of
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12,000 Sm3/day. After a short initial ramp up phase, the start of the
injection and
production zones are retracted at a rate of 4 m every 60 days, or at an
average rate
of 0.0667 m/day. The length of each production zone is increased as the
injection
zones moves closer towards the heel of the well bore. A fixed distance of 24 m
exists
between adjacent injection zone and production zones.
[0422] Figure 21 shows the configuration of the injection and production
zones
along the horizontal well bore 2010 and contours of temperature in the
reservoir
2006 on days: (a) 396, (b) 762 and (c) 1157. The behaviour of the process is
the
similar to that shown for the single injection point in Example 1, albeit with
two
injection zones, and two corresponding zones of mobilised fluids in the
reservoir and
two production zones in the well bore. The combustion zones 2021 are regions
of
high temperature where the oxidant reacts with the hydrocarbons in the
reservoir to
generate heat. Lower temperature zones 2022, 2023 and 2024 exist around each
combustion 2021 and reduce the viscosity of the oil enabling it to flow as
produced
fluids 2016 into the well bore. The individual injection and production zones
can be
designed to operate independently of each other, by ensuring that the oxidant
2008
is distributed equally between the two injection zones.
[0423] The original oil in place for the reservoir domain is 38,400 m3. The
produced oil rate averages 8.6 m3/day. Over the period of 1765 days, the
cumulative
oil production to surface is 12,841 m3 yielding an oil recovery factor of 33.4
A) vs
32.6 A) for the single point simulation. Table 6 shows a summary of the
simulation
results. It can be seen that the production results for the two point MICS
configuration are double that of the single point simulation. Thus, the single
point and
two point MICS simulations can be considered representative of 100 m and 200 m
long sections of the reservoir, respectively.
[0424] A typical horizontal well can be 1,000 m in length. By adding more
injection and production zones the oil in place can be produced more quickly.
Table
6 also shows data scaled from the single point simulation for a 1000 m section
of the
reservoir with a MICS well configured hypothetically for five point and ten
point
injection. With five injection and production zones, the average oil
production will be
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20.1 m3/day over 3,530 days, while with ten injection and production zones the
average oil production will be 40.2 m3/day over 1,765 days. The total oil
produced
from a 1000 m well is 62,620 m3 or approximately 393,000 barrels of oil.
Table 6
Computer simulation results
Parameter Units Single Two Five Ten
point point point point
MICS MICS MICS MICS
Axial length of domain m 100 200 1000 1000
Original oil in place m3 19,200 38,400 192,000
192,000
Total simulation time days 1,765 1,765 3,530 1,765
Air injection rate Sm3/day 6,000 12,000 30,000
60,000
Average oil production rate m3/day 4.2 8.6 20.1 40.2
Average air oil ratio m3/m3 1,423 1,408 1,423 1,423
Oil produced to surface m3 6,262 12,841 62,620
62,620
Oil recovery factor % 32.6 33.4 32.6 32.6
Example 3: Single well Steam Assisted Gravity Drainage processes
[0425] This example has been prepared using computer simulations of the
recovery process using the STARSTm Thermal Simulator general issue 2018,
provided by Computer Modelling Group of Calgary, Alberta, Canada.
[0426] The thermo-physical properties of the heavy oil and properties of
the
reservoir are taken from the work of Zhao et al. (D. W. Zhao, J. Wang and I.
D.
Gates, "Thermal recovery strategies for thin heavy oil reservoirs", Fuel,
v117,
pp431-441, 2014). Table 7 provides a summary of the main parameters used.
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Table 7
Reservoir Parameters
Parameter Units
Value
Porosity % 0.32
Permeability lateral (X, Y) mD 3650
Permeability vertical (Z), assumed 80% of lateral permeability mD 2920
Reservoir Pressure kPag 2800
Dead oil viscosity at 20 C
20 C cP
15,212
40 C cP 1884
80 C cP
125.4
160 C cP 9.66
250 C cP 3.09
Oil saturation % 65
Water saturation % 35
[0427] The computational domain is 80 m (axially) x 10 m (vertically) x
50 m
(laterally) and represents a small section of the reservoir. The lateral sides
of the
computational domain are modelled with symmetry boundary conditions. The 80 m
axial section represents a portion of a typical horizontal well which may be
over 1000
m in length. The lateral extent of 50 m assumes that the adjacent well bores
are
spaced 100 m apart on a repeating pattern in the reservoir. Table 8 shows the
main
computer simulation parameters.
Table 8
Computer simulation parameters
Parameter Units
Value
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Depth to top of oil reservoir m 334
Depth to bottom of oil reservoir m 344
Oil reservoir thickness m 10
Length of reservoir m 80
Lateral extent of reservoir m 50
Injection/production well, height above bottom of reservoir m 1.5
Pay thickness of reservoir above Injection/Production well m 8.5
Injection/Production well horizontal length m 80
Steam injection pressure kPag 4000
Steam injection rate m3/day
16.67 (max)
Production pressure kPag 500
Maximum steam production m3/day
0.133 (max)
[0428] Simulations are made of a Moving Injection SAGD (MI-SAGD) process
and a Cyclic Injection SAGD (CI-SAGD) process which are both embodiments of
the
present method and system and which both use a single horizontal well bore.
The
MI-SAGD process in this example has a well configuration like that of Example
1
with steam being used as the mobilising fluid. The steam injection zone is
moved
along the horizontal well bore and the production zone is expanded as the
reservoir
is swept of oil as in Example 1. The CI-SAGD process uses a pattern of
injection and
production zones in the well bore which is cycled in time to establish the
development of a pseudo steady steam chamber around the well bore. The MI-
SAGD and CI-SAGD simulation results are compared with a conventional SAGD
dual well configuration in which an injection well is located several metres
above the
production well. Table 9 provides details of the well configurations used for
the
simulations. For the CI-SAGD process the steam is injected as per the regular
pattern given by Figure 16(b), with a 3 month duration for each stage, and 4
stages
for the cycle, yielding a cycle time of 12 months.
Table 9
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Well configurations
Cyclic Moving
Injection Injection Dual well
Parameter Units SAGD SAGD SAGD
Injection zone length m 10 5 80
Production zone length m 10 varies 80
Lateral distance between
injection and production
zones m 20 10 n/a
Stage time months 3 n/a n/a
Cycle time months 12 n/a n/a
Injection zone movement m/day n/a 0.033 n/a
Injection well position
from bottom of reservoir m 1.5 1.5 5.5
Production well position
from bottom of reservoir m 1.5 1.5 1.5
[0429] Table 10 shows the results of
the simulations, compared after a period of
4 years of operation. The resultant steam oil ratios at this time
approximately
correspond to the economic cut-off for operations of SAGD in thicker
reservoirs. It
can be seen that the conventional dual well SAGD process has a recovery factor
of
62.2 % and a cumulative steam oil ratio (cSOR) of 5.6 m3/m3, while at the same
time
the MI-SAGD process has a recovery factor of 53.4 % and a cumulative steam oil
ratio (cSOR) of 6.4 m3/m3. The lower performance of the MI-SAGD process is due
to
the fact that the steam chamber is not pseudo-steady and thus there is a
relatively
larger heat loss area per unit of production. The CI-SAGD process has
marginally
better performance than the dual well SAGD with a recovery factor of 62.3 %
and a
cSOR of 5.5 m3/m3. The CI-SAGD process of the current method thus achieves
equivalent performance to the dual well SAGD but has the advantage that only a
single well bore is drilled into the formation. This can make it cheaper and
easier to
drill and complete, especially in thin seams, than the dual well design.
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Table 10
Computer simulation results
Cyclic Moving
Injection Injection Dual well
Parameter Units SAGD SAGD SAGD
Total simulation time days 1460 1460 1460
Average steam injection
rate m3/day 589 584 589
Average oil production rate m3/day 106 91 106
Cumulative steam oil ratio m3/m3 5.5 6.4 5.6
Oil produced to surface m3 155,060 133,358
154,865
Oil recovery factor % 62.3 53.4 62.2
Example 4: Moving Injection Waterflood Enhanced Oil Recovery in a Fractured
Reservoir (MI-E0R)
[0430] This example has been prepared using computer simulations of the
recovery process using the MATLAB Reservoir Simulation Toolbox (MRST) Version
2017, developed in part by Sintef of Norway (K-A. Lie, An introduction to
reservoir
simulation using MATLAB/GNU Octave: User guide for the MATLAB Reservoir
Simulation Toolbox (MRST). Cambridge University Press, 2019, ISBN
9781108492430).
[0431] The simulations have been made using a three phase black oil
model.
The reservoir is a light oil with an initial oil saturation of 80 A) and an
initial water
saturation of 20 %. The reservoir rock has a porosity of 30 A) and a
permeability of
1000 millidarcy. The oil density is 700 kg/m3 with a viscosity of 5 centipoise
(cp),
while the water density is 1000 kg/m3 with a viscosity of 1 cp at the
reference
conditions of 100 bara and 20 C. The gas phase is not present and models for
dissolved gas and vaporised oil are turned off.
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[0432] The computational domain is 500 m (axially) x 100 m (vertically) x
200 m
(laterally) and represented with 50 x 10 x 20 cells (i.e. cells of 10 x 10 x
10 m3). A
horizontal injection well of 500 m length is positioned on one side and at the
bottom
of the reservoir. A horizontal production well of 500 m is positioned on the
other side
and at the top of the reservoir and operates at a production pressure of 50
bara.
Each horizontal well has a diameter of 0.2 m. Figure 22 shows the reservoir
domain
and horizontal wells.
[0433] The pore volume of the reservoir is 3,000,000 m3 while the original
oil in
place for the reservoir domain is 2,400,000 m3 (without fractures). Over a
period of
3650 days (10 years) a total of 5 reservoir pore volumes of water are injected
into
the reservoir.
[0434] The fractures have a porosity of 80 A) and a permeability of 10,000
darcy.
The position of horizontal fractures, which bisect the entire reservoir, are
generated
randomly during each computer simulation. The computer simulations have been
conducted with 0, 5, 10 and 20 fractures. Figure 22(a) shows a schematic of
the
reservoir computational domain 2106, the location of the injection well 2110
and the
production well 2111 and the location of fractures 2120, for the case of 5
fractures.
[0435] The water is injected in two configuration modes. In the static
configuration, the water is injected along the entire horizontal well bore
throughout
the entire simulation. In the moving injection configuration, the water is
injected
across a 50 m zone of the well bore and the position of this injection zone is
moved
from the toe of the well to the heel of the well over the simulation period.
The moving
injection zone can be achieved using embodiments of the present disclosure. It
should be noted that the total volume of water injected in all cases has been
kept
constant.
[0436] Table 6 shows a summary of the simulation results. It can be seen
that in
a homogeneous reservoir, with 0 fractures, that the static and moving
injection
configurations yield similar results for the total oil and water produced, the
produced
water/oil ratio and the oil recovery factor. In the homogenous case, the oil
recovery
factor is 78 ¨ 79 A) for both configurations. As the reservoir becomes more
and more
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fractured, the performance of the static injection configuration deteriorates
significantly, while the performance of the moving injection configuration
deteriorates
to a much lower degree. For example, in the presence of 10 fractures, the oil
recovery factor for the static injection configuration is 49.7 A) versus 62.1
A) for the
moving injection configuration. Similarly, with 20 fractures the oil recovery
for the
static configuration is only 31.7 A) compared with 61.7 A) for the moving
injection
configuration. Therefore, the moving injection configuration outperforms the
static
injection configuration in a fractured reservoir, where the fractures are
predominately
orientated perpendicular to the wells.
[0437] Figure 22(b)-(c) shows the oil saturation at the end of 10 years of
waterflooding operations. The zone 2131 is largely swept of oil and contains
mostly
water, while zone 2132 has a high degree of oil remaining, notably 20-50%.
Zone
2133 has a low oil saturation <20%, while zone 2134 is essentially just water.
It can
be seen, that in the case of the static configuration, shown in Figure 22(b)
that large
volumes of oil remain unrecovered between the fractures in zone 2132 because
the
water flows preferentially through the high permeability fractures forming
zone 2131.
In contrast, the contours of oil saturation for the moving injection case,
Figure 22(c),
shows a lower average and lower variability in oil saturation, which
translates into
higher oil recovery. In particular, the zone 2134 of low oil saturation
extends over a
larger zone which penetrates more deeply into the reservoir between the wells.
Zones of high oil saturation 2132 are restricted to ends of the reservoir
which are
influenced by the start-up and shut-down procedure of the moving injection
configuration.
[0438] It can be observed from the data that the moving injection
configuration
positively limits the degree of water by-passing through the fractures.
Table 11
Computer simulation results.
Number of Horizontal Fractures
Parameter Units
0 5 10 20
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Static injection configuration
Total oil produced m3 1,916,273 1,586,886 1,195,082
763,045
Total water produced m3 13,083,953 13,429,502
13,837,498 14,310,752
Produced water/oil ratio 6.8 8.5 11.6 18.7
Oil recovery factor % 79.8 66.1 49.7 31.7
Moving injection configuration
Total oil produced m3 1,883,401 1,618,872 1,493,187
1,485,931
Total water produced m3 13,116,836 13,397,499
13,539,248 13,578,516
Produced water/oil ratio 7.0 8.3 9.1 9.1
Oil recovery factor % 78.5 67.4 62.1 61.7
Example 5: Moving Injection Waterflood Enhanced Oil Recovery in Multiply
Fractured Reservoirs (MI-E0R)
[0439] The
simulations were made using the same reservoir model as described
for Example 4. In this example, fractures are orientated perpendicular and
parallel to
the horizontal well bores and the size and orientation of each fracture are
generated
randomly within pre-determined bounds during each computer simulation. The
fractures may intersect with one another, and hence create complex fluid flow
pathways within the reservoir and potentially between the injection and
production
wells. The computer simulations have been conducted with a total of 6, 12, 18
and
23 fractures.
[0440] The
water is injected in two configuration modes as in Example 4. In the
static configuration, the water is injected along the entire horizontal well
bore
throughout the entire simulation. In the moving injection configuration, the
water is
injected across a 50 m zone of the well bore and the position of this
injection zone is
moved from the toe of the well to the heel of the well over the simulation
period. The
moving injection zone can be achieved using embodiments of the present
method/system. It should be noted that the total volume of water injected in
all cases
has been kept constant.
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[0441] Table 12 shows a summary of the simulation results. As the reservoir
becomes more and more fractured, the performance of the static injection
configuration deteriorates significantly, while the performance of the moving
injection
configuration deteriorates to a much lower degree. For example, in the
presence of
fractures, the oil recovery factor for the static injection configuration is
48.7 A)
versus 56.2 A) for the moving injection configuration. Similarly, with 23
fractures the
oil recovery for the static configuration is 33.9 A) compared with 50.0 A)
for the
moving injection configuration. Therefore, the moving injection configuration
outperforms the static injection configuration in a generally fractured
reservoir.
[0442] Taken together, Examples 4 and 5, show that the moving injection
concept increases the oil recovered compared to the static injection
configuration
whichever way the fractures are orientated. Thus, in fields with high levels
of
fracturing, which are not well known a priori, implementing a moving injection
configuration should deliver equal or better oil recovery from the reservoir
than is
expected from a static injection configuration.
Table 12
Computer simulation results.
Total Number of Fractures
Parameter Units 6 12 18 23
No. perpendicular fractures 5 10 15 20
No. parallel fractures 1 2 3 3
Static injection configuration
Total oil produced m3 1,519,876 1,171,145 949,238
817,362
Total water produced m3 13,499,209 13,865,012
14,104,452 15,068,728
Produced water/oil ratio 8.9 11.8 14.9 17.4
Oil recovery factor % 63.3 48.7 39.4 33.9
Moving injection configuration
Total oil produced m3 1,567,767 1,352,806 1,306,588
1,205,696
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Total water produced m3 13,451,294 13,683,261
13,746,928 12,863,616
Produced water/oil ratio 8.6 10.1 10.5 11.5
Oil recovery factor 0/0 65.2 56.2 54.3 50.0
Example 6: Multi-well Moving Injection Combustion Stimulation (MICS)
[0443] This example was derived from the computer simulations of two
predominately horizontal wells located in a reservoir, each as shown in
Example 1.
Figure 23 shows plan views of a reservoir depicting the location of two
predominately
horizontal wells and contours of temperature on the plane in the middle of the
reservoir, at three different times, for a Moving Injection Combustion
Stimulation
(MICS) process. There are two predominately horizontal wells, 2210 and 2211,
respectively, drilled into the reservoir which are both configured for
injection of
mobilising fluids and production of reservoir fluids using a single well, like
that shown
in Examples 1 and 2 and using a well completion similar to that shown in
Figures 1
and 2.
[0444]
Figure 23(a) shows the temperature profile in the reservoir 2206, at a time
when the injection zone of the oxidant is close to the toe of the wells (i.e.
at the
beginning of the wells' life). The reaction of the oxidant with the
hydrocarbons in the
reservoir 2206, generates combustion zones 2221 with a temperature of over 400
C, which extend laterally towards the centre-line between the wells. Zones
2222
exists around the combustion zones where the temperature is between 300 and
400
C. Similarly, lower temperature zones 2223 exists where temperatures are
between
200 and 300 C. Evaporation zones 2224 exist around the combustion process
where temperatures vary between 100 and 200 C and where water originally
present in the reservoir 2206 can be turned to steam. The reservoir 2206 has a
natural temperature below 100 C, and typically between about 20 and 30 C. At
this
time, the thermally affected regions generated by the combustion zones 2221 do
not
substantially interact with each other, and the production from each well is
equivalent
to that of an isolated well bore undergoing the same process.
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[0445] Figure 23(b) shows the temperature profile in the reservoir 2206, at
a time
when the injection zone of the oxidant is close to the middle of the wells (at
the
middle of well life). The reaction of the oxidant with the hydrocarbons in the
reservoir
2206, generates combustion zones 2221 with a temperature of over 400 C, which
extend laterally towards the centre-line between the wells. Zones 2222 exists
around
the combustion zone where the temperature is between 300 and 400 C.
Similarly,
lower temperature zones 2223 exists where temperatures are between 200 and 300
C. The evaporation zones 2224 generated from each combustion process vary
between 100 and 200 C and may merge together to form a single low temperature
zone of over 100 C, where water originally present in the reservoir 2206 can
be
turned to steam. At this time, the thermally affected regions generated by the
combustion zones start to interact with each other, and the production from
both
wells increases above twice that produced from an isolated well bore.
[0446] Figure 23(c) shows the temperature profile in the reservoir 2206, at
a
time when the injection zone of the oxidant is close to the heel of the wells
(at the
end of well life). At this time, the thermally affected regions generated by
the
combustion zones interact with each other substantially. The production from
both
wells is above twice that produced from an isolated well bore and the air oil
ratio is
below that found from a single well configuration, due to the lower heat
losses
experienced by the thermally affected zone.
[0447] The magnitude of the additional oil recovery from the two well MICS
process, depends on various properties of the reservoir, the well bores and
the
oxidant injection configuration. If the two horizontal wells are spaced very
far apart,
then the thermally affected zones will not interact at all, and the production
will be
twice that of an isolated well bore undergoing the same process. If the two
horizontal
wells are spaced very close together, then the thermally affected zones will
largely
overlap, and the production could be lower than twice that of an isolated well
bore. If
the wells are spaced optimally, then the thermally affected zones will have a
small
overlap and the production will be higher than two individual wells and the
AOR will
be lower, indicating a more efficient process. For the combustion of heavy oil
and oil
sands bitumen from reservoirs in Alberta and Saskatchewan in Canada, the
lateral
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distance between two horizontal well bores is preferably, between about 40 and
100
metres, and more preferably between about 50 and 75 metres.
Example 7: Multi-well Moving Injection Combustion Process
[0448] Figure 24 shows plan views of a reservoir depicting the location of
two
predominately horizontal wells and contours of temperature on the plane in the
middle of the reservoir, at three different times, for a Moving Injection
Combustion
process. There are two predominately horizontal wells, with the well 2310
designated
as the injection well and well 2311, designated as the production well. The
well
completions in 2310 and 2311 are similar to the completions shown in Figure
18,
albeit with only one injection zone along the injection well 2310. The oxidant
is
injected into the reservoir from the injection well 23101, from an injection
zone which
extends about 20 m and which is moved slowly along the injection well 2310,
from
the toe towards the heel. The fluids mobilised by the combustion process are
recovered in the production well 2311 and transported to surface.
[0449] Figure 24(a) shows the temperature profile in the reservoir 2306, at
a time
when the injection zone of the oxidant is close to the toe of the injection
well 2310
(ie. at the beginning of the well's life). The reaction of the oxidant with
the
hydrocarbons in the reservoir 2306, generates a combustion zone 2321 with a
temperature of over 400 C, which extend laterally towards the centre-line
between
the wells. Zone 2322 exists around the combustion zone where the temperature
is
between 300 and 400 C. Similarly, a lower temperature zone 2323 exists where
temperatures are between 200 and 300 C. An evaporation zone 2324 exists
around
the combustion process where temperatures vary between 100 and 200 C and
where water originally present in the reservoir 2306 can be turned to steam.
The
reservoir 2306 has a natural temperature below 100 C, and typically between
about
20 and 30 C. At this time, the thermally affected region generated by the
combustion zone 2321 is skewed due to the fact that the injection zone where
the
oxidant is injected into the reservoir is moved slowly from the toe to the
heel of well
2310. The moving injection zone therefore begins to establish an oblique
combustion
front between the injection well 2310 and the production well 2311.
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[0450] Figure 24(b) shows the temperature profile in the reservoir 2306, at
a time
when the injection zone of the oxidant is close to the middle of the injection
well 2310
(ie. at the middle of well life). The reaction of the oxidant with the
hydrocarbons in the
reservoir 2306, generates a combustion zone 2321 with a temperature of over
400
C, which forms an oblique combustion front between the two horizontal wells.
Lower
temperature zones 2322 and 2323 extend around the combustion zone. An
evaporation zone 2324 exists where temperatures vary between 100 and 200 C
and
where water originally present in the reservoir 2206 can be turned to steam.
At this
time, a fully established oblique combustion front is present between the
injection
well 2310 and the production well 2311.
[0451] Figure 24(c) shows the temperature profile in the reservoir 2306, at
a time
when the injection zone of the oxidant is close to the heel of the injection
well 2310
(ie. at the end of well life). At this time, the thermally affected region
includes a
skewed combustion zone 2321 where hydrocarbons are oxidised and temperatures
are over 400 C, and lower temperatures zones 2322, 2323 and 2324. At this
time,
the majority of the hydrocarbons in the reservoir between the two wells has
been
produced to surface. The injection zone is moved close to the heel of the well
2310,
but sufficiently far away that the maximum temperature in the vertical section
of the
well bore is maintained below a safe limit, typically below 300 C, and more
preferably below 200 C and even more preferably below 100 C.
[0452] When the efficiency of the process drops, the injection of the
oxidant can
be stopped and hydrocarbons remaining in the reservoir may be produced to
surface
using natural and/or artificial lift as the reservoir slowly cools back down
to its natural
temperature.
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